NETA World Journal | Winter 2015

Energize Your Future

PowerTest heads to Fort Worth, Texas in 2016

If you ask the people of Fort Worth, Texas to talk about their city, they might recount beginnings as a small outpost on a lonely frontier. Unusual, perhaps, in a state where everything is bigger. But, eventually Fort Worth lived up to its state’s big reputation, growing to the fifth-largest city in Texas with about 800,000 people today who are ready to take on modern challenges for expansion and growth. Its cattle and oil beginnings have been interwoven with an array of diverse industries.

PowerTest draws many parallels to Fort Worth. While no one can claim they have been lonely at PowerTest, the premier electrical maintenance and safety event has grown in similar fashion, seizing opportunities to help industry professionals grab the bull by the horns and jump to the top of their game. Fort Worth’s mission to work together to build a strong community describes the PowerTest commitment to build a network of knowledgeable professionals in the electrical safety industry, working together to uphold the standards and improve safety and reliability.

Deep in the heart of Texas, PowerTest 2016 comes to Fort Worth to plug into the city’s vast energy and connect attendees with leading industry experts, high power learning, and networking. Everything’s bigger in Texas, including the opportunities for you at PowerTest 2016.

Keynote Speaker: Gary Norland

Gary Norland is a husband, father, electrician, and speaker.

Gary spent several years traveling and working various jobs in construction. He eventually went to work as a union maintenance electrician for his local pulp and paper mill – no more travel, a good income, and stability.

He was a healthy six-foot-three, 240-pound man who loved his work was always about getting the job done. But one day, his life changed electrocuted by a 12,500-volt, 200-amp overhead power line. He ish dy morning to share with you how hard work and dedication to your jobhldb focus, but not your only focus. Gary wants others to understand that if y ’ safety seriously, your life could resemble his in less than a second.

His attitude d when he was s here Monday b should be a you don’t take

ar y Norland

Safety Presentations

MONDAY

We’ve gathered leaders in the industry and will stage a full day of engaging, 45-minute presentations sure to expand your thinking and generate new ideas. Choose from 27 detailed presentation track topics.

Technical Presentations

ELECTRICAL SAFETY

• Protective Devices Maintenance and the Potential Impact on Arc-Flash Incident Energy

Dennis Neitzel, AVO Training Institute, Inc.

• Beliefs Drive Behaviors

D. Ray Crow, DRC Consulting Ltd.

• Potential Impact of ISO 55000 on Maintenance Critical to Electrical Safety

H. Landis Floyd, Electrical Safety Group, Inc.

• Electrical Safety Management System Principles and Practices

Mike Doherty, Shermco Industries Canada

• Overview of an Electrical Safety Program Development Guide

Terry Becker, Electrical Safety Program Solutions, Inc.

• Arc-Flash Mitigation by Transformer Differential Relay Protection

Mose Ramieh III, PGTI, and Randall Sagan, MBUSI

RELIABILITY

• System Testing of Protection Devices and Schemes –What Is It and Why Do We Need It?

Will Knapek, Benton Vandiver, and Alexander Apostolov, OMICRON Corp. USA

• Improving Safety through Partial Discharge Surveying

Tony McGrail, Doble Engineering Company

• Transformer Failures and Case Study

Shuzhen Xu, FM Global

• Protecting Batteries that Protect Your Power System

Brandon Schuler, Electrical Reliability Services

• Power Quality Monitoring and Communications Standards Update

Ross Ignall, Dranetz Technologies

• How Disruptions in DC and Communications Affect Protection

Karl Zimmerman

Schweitzer Engineering Laboratories, Inc.

EQUIPMENT

• Bushing Replacement – It Fits, But Will It Work?

Keith Hill, Doble Engineering Company

• Gaps in Motor Reliability

Lona Mazzeo, PDMA

• Reliability of Electrical Systems: From Testing to Monitoring

Alan Ross, SD Myers

• Understanding and Testing Motor Overload Protection and Thermal Models

Daniel Ransom, Doble Engineering Company

• Electric & Dielectric Condition Assessment of HV Current Transformers

Diego Robalino, Megger

• Understanding Transformer Differential Protection

J Scott Cooper, OMICRON electronics Corp. USA

CIRCUIT BREAKERS

• Power Factor Testing for SF6 Breakers

Rick Youngblood, Doble Engineering Company

• Vacuum Interrupters: Pressure Vs. Age – A Study of Vacuum Levels in 314 Service Age Vacuum Breakers

John Cadick, Cadick Corporation

• Effects of Low-Resistance Measurement Instruments on Protection and Control Devices

Dinesh Chhajer and Jammie Lee, Megger

• Diagnostic Testing Practices for SF6-Filled Dead Tank Circuit Breakers

Charles Sweetser, OMICRON electronics Corp. USA

• What is TankLoss Index?

Rick Youngblood, Doble Engineering Company

• Circuit Breaker and Transducer: Where Do I Connect?

Robert Foster, Megger

ELECTRICAL COMMISSIONING

• Application and Commissioning of On-line Partial Discharge Technology to Medium-Voltage Switchgear

Bruce Rockwell, American Electrical Testing Co., Inc.

• Electrical Commissioning Tips and Trends for Advanced Critical Facilities Applications

Corey Dozhier, Oracle

• Electrical Testing and Inspection of Equipment in Questionable Condition

Peter Brosz, Brosz Group of Companies

TUESDAY (CONTINUED)

Tuesday Afternoon

POWERTEST 2016 TRADE SHOW

The PowerTest 2016 Trade Show promises more than 100 toptier electrical power vendors whose mission is electrical safety and reliability. Enjoy a complimentary lunch and beverages as you tour the show and make connections. New this year, we have expanded the hours of the trade show. The PowerTest 2016 Trade Show will take place from 12:00 – 6:00 PM.

Tuesday Evening

DON’T MISS THE POWERTEST 2016 POWERBASH RECEPTION!

A gathering you don’t want to miss. Enjoy the Western charm and music of Texas, celebrate the best of PowerTest, mix and mingle. Tuesday evening from 7:00 – 10:00 PM.

POWERTEST 2016 EXHIBITORS

SPECIAL SESSIONS AND MORE

Megger Best Practices

Sunday, March 13 | 9:00 AM – 4:00 PM

Megger’s seminar will address many of the critical and costly aspects of substation maintenance. The interactive session will feature practical presentations on current methods and practices to help ensure the reliability of high-voltage circuit breakers, power transformers, and batteries. You must preregister for this event by contacting Megger: 214-330-3514.

Stockyards Station Shindig

SUNDAY, MARCH 13 | 5:30 PM – 8:30 PM

Join us Sunday evening for traditional Texas hospitality and a wrangling good time. Swagger into the Stockyards Station and experience the storied history of Fort Worth, the best in Southwest BBQ, a few tall cold ones, and a rootin’-tootin’ showdown! $155 per person.

PowerDB User Group

MONDAY, MARCH 14 | 12:00 PM – 2:00 PM

Annual User’s Group Meeting open to licensed users of PowerDB Pro Software. Agenda will include presentations by the PowerDB Pro development team as well as utility, industrial, and contractor groups discussing how this product is an integral part of their business operations.

Spouse/Guest Pass

A special lounge exclusively for spouses and guests of PowerTest attendees, stocked daily with light refreshments and information on local activities. Includes admission to Hospitality Suites Monday evening, Tuesday Trade Show, and Tuesday evening PowerBash reception. $75 per person.

Social Pass

The Social Pass includes admission to the Hospitality Suites, Trade Show, and the PowerBash reception. $50 per person.

EARLY BIRD REGISTRATION IS NOW OPEN

REGISTER

EASY STEPS FOR REGISTRATION

(NETA)

& Tuesday$995$895 Monday – Thursday$1895$1695

REGISTER ON-LINE

To register for PowerTest 2016, save time by registering online. You’ll find a complete brochure and registration form available at www.powertest.org

HOTEL RESERVATIONS *

Omni Fort Worth Hotel 888-444-OMNI 1300 Houston Street Fort Worth, TX 76102

Reservation Deadline: February 5, 2016

Group Name: NETA/PowerTest

Group Rate: $209

* Once you register for PowerTest 2016, you will receive a link via email to secure your hotel reservations at the Omni Fort Worth.

PAYMENT

NETA accepts all major credit cards. Save time and register on-line at www.powertest.org or call 888-300-6382 (NETA)

EXTRAS

PowerTest 2016 Technical Papers – Registered conference attendees will receive all PowerTest technical presentations on a USB drive in their registration bag.

1. Go to www.powertest.org and review the complete PowerTest 2016 on-line brochure.

2. Decide the number of days you will attend the conference.

3. Tuesday attendees select up to two panels. (Cost of panels included in the registration fees.)

4. Wednesday attendees register for up to two seminars.

(Cost of seminars included if registered for Monday – Thursday.)

5. Thursday attendees register for up to two seminars (Cost of seminars included if registered for Monday – Thursday.)

6. Register for Doble Lab Seminar. (Cost of seminar is in addition to the registration fees.)

7. Sign up for Spouse/Guest Passes. (Cost of passes is in addition to the registration fees.)

8. Sign up for PowerTest 2016 conference polo shirts and select size. (Cost of polo shirts is in addition to the registration fees.)

Fort Worth, Texas

COVER STORY

66Transformer Maintenance: The Overlooked Items

In my 35 years of involvement with substation transformer maintenance, I have witnessed widely varying perspectives on what maintenance should include. Too often, it is limited to nothing more than inspections. The techs involved might look at the top oil and hot spot indicators, observe the nitrogen pressure or conservator levels, check for leaks — and maybe, if they are thorough — log the load tap changer (LTC) counter. Most technicians comment that the transformer is electrically tested every three to six years by performing the standard regiment of power factor, TTR, excitation, and winding resistance tests; but the majorities are completely unaware of what I call the “overlooked items.”

Rick Youngblood, Doble Engineering Company

FEATURES

7 President’s Desk

Ron Widup, Shermco Industries

NETA President

75Working Safely with Power

Transformers in the Utility Sector

Ray Curry, American Transmission Company

80Transformer Testing Techniques and Standard Development

Diego M. Robalino, PhD, PMP, Megger – AVO Training Institute

See Special Insert PowerTest 2016 Preview Guide

IN EVERY ISSUE

11 NFPA 70E and NETA

First Draft Meeting of the 70E 2018 Cycle

Ron Widup and Jim White, Shermco Industries

18 Niche Market

Transformer Insulation Degradation

Lynn Hamrick, Shermco Industries

28 Tech Quiz

Power Transformers

Jim White, Shermco Industries

30 No-Outage Corner

Case Study: Location of Generator PD Sources

Using Multiple Sensors

Don A. Genutis, Halco Testing Services

42 Tech Tips

Personal Protective Grounding

Jeff Jowett, Megger

48 Safety Corner

Power Transformer Hazard Awareness

Scott Blizard, American Electrical Testing Co., Inc.

55 Relay Column

Modern Advances in Testing Multifunction

Numerical Transformer Protection Relays

Steve Turner, Beckwith Electric Company, Inc. INDUSTRY TOPICS

97 Combined Current and VoltageControlled Source in Arcing Contacts Condition Assessment

Adnan Secic and Radenko Ostojic, DV Power, Sweden

SPECIFICATIONS AND STANDARDS 120 ANSI/NETA Standards Update

Insulated Conductor Committee Meeting Report

Ralph Patterson, Power Products & Solutions LLC 126 IEEE/PES Transformers Committee Meeting Report

Al Peterson, Utility Service Corporation

Sunshine, Sea, and Blue Skies Greet NETA Members in Seattle, Washington Kristen Wicks, NETA

Lorne Gara, Orbis Engineering Ltd.

Top 10 Career-Building Reasons to Attend PowerTest 2016

Join the Spotlight with NETA Corporate Alliance Partners

NETA Alliance Partnership Program – Join and Save at PowerTest 2016

Doble Engineering Seminar Expands Learning to Friday

Ensuring Access to the Right Equipment at the Right Time – And at the Lowest Cost

Herb Ostenberg, Electro Rent Corporation

NETA Accredited Companies

Advertiser List

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Portage, MI 49024

Toll free: 888.300.NETA (6382)

Phone: 269.488.NETA (6382)

Fax: 269.488.6383

neta@netaworld.org

www.netaworld.org

EXECUTIVE DIRECTOR: Jayne Tanz, CMP

NETA Officers

PRESIDENT: Ron Widup, Shermco Industries

FIRST VICE PRESIDENT: Jim Cialdea, Three-C Electrical Co., Inc.

SECOND VICE PRESIDENT: Scott Blizard, American Electrical Testing Co., Inc.

SECRETARY: Mose Ramieh, Power & Generation Testing, Inc.

TREASURER: John White, Sigma Six Solutions

NETA Board of Directors

Ken Bassett (Potomac Testing, Inc.)

Scott Blizard (American Electrical Testing Co., Inc.)

Jim Cialdea (Three-C Electrical Co., Inc.)

Lorne Gara (Orbis Engineering Field Services, Ltd.)

Roderic Hageman (PRIT Service, Inc.)

David Huffman (Power Systems Testing)

Alan Peterson (Utility Service Corporation)

Mose Ramieh (Power & Generation Testing, Inc.)

Bob Sheppard (Southwest Energy Services, LLC)

John White (Sigma Six Solutions)

Ron Widup (Shermco Industries)

NETA World Staff

TECHNICAL EDITORS: Roderic L. Hageman, Tim Cotter

ASSOCIATE EDITOR: Resa Pickel

MANAGING EDITOR: Jayne Tanz, CMP

ADVERTISING MANAGER: Laura McDonald

DESIGN AND PRODUCTION: Hour Custom Publishing

NETA Committee Chairs

CONFERENCE: Ron Widup; MEMBERSHIP: Ken Bassett; PROMOTIONS/MARKETING: Scott Blizard; SAFETY: Scott Blizard and Jim White; TECHNICAL: Alan Peterson; TECHNICAL EXAM: Ron Widup; CONTINUING TECHNICAL DEVELOPMENT: David Huffman; TRAINING: Kerry Heid; FINANCE: John White; NOMINATIONS: Alan Peterson; STRATEGY: Mose Ramieh; ALLIANCE PROGRAM: Jim Cialdea

© Copyright 2015, NETA

NOTICE AND DISCLAIMER

NETA World is published quarterly by the InterNational Electrical Testing Association. Opinions, views and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees or agents (herein “NETA”).

All technical data in this publication reflects the experience of individuals using specific tools, products, equipment and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA.

NETA MAKES NO ENDORSEMENT, REPRESENTATION OR WARRANTY AS TO ANY OPINION, PRODUCT OR SERVICE REFERENCED OR ADVERTISED IN THIS PUBLICATION. NETA EXPRESSLY DISCLAIMS ANY AND ALL LIABILITY TO ANY CONSUMER, PURCHASER OR ANY OTHER PERSON USING ANY PRODUCT OR SERVICE REFERENCED OR ADVERTISED HEREIN FOR ANY INJURIES OR DAMAGES OF ANY KIND WHATSOEVER, INCLUDING, BUT NOT LIMITED TO ANY CONSEQUENTIAL, PUNITIVE, SPECIAL, INCIDENTAL, DIRECT OR INDIRECT DAMAGES. NETA FURTHER DISCLAIMS ANY AND ALL WARRANTIES, EXPRESS OF IMPLIED, INCLUDING, BUT NOT LIMITED TO, ANY IMPLIED WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE.

ELECTRICAL TESTING SHALL BE PERFORMED ONLY BY TRAINED ELECTRICAL PERSONNEL AND SHALL BE SUPERVISED BY NETA CERTIFIED TECHNICIANS/ LEVEL III OR IV OR BY NICET CERTIFIED TECHNICIANS IN ELECTRICAL TESTING TECHNOLOGY/LEVEL III OR IV. FAILURE TO ADHERE TO ADEQUATE TRAINING, SAFETY REQUIREMENTS, AND APPLICABLE PROCEDURES MAY RESULT IN LOSS OF PRODUCTION, CATASTROPHIC EQUIPMENT FAILURE, SERIOUS INJURY OR DEATH.

PRESIDENT’S DESK

Transforming your world, transforming the industry, transforming the way you think about electrical power system testing and maintenance — that’s an important part of what we try to do here at NETA, and we use the NETA World Journal as a conduit of information for all things electrical.

Have you ever thought of writing an article about the industry? How about a case study from one of your projects? We welcome your submissions and encourage you to expand and communicate what’s going on in our industry.

Entering the winter months, many of you will have a little extra time on your hands as the days get shorter and the nights (that time for writing) get longer. Why not use that time to memorialize our industry — and build your own reputation in the field — with an article submission to the NETA World Journal?

And as we prepare for our annual technical conference, PowerTest, we are especially excited because it will be in Fort Worth, Texas, on March 14-18, 2016. Mark your calendars now and get registered for the conference — it’s sure to be a good one, y’all.

Sincerely,

Ron Widup President InterNational Electrical Testing Association

nce, PowerTest, we are Texas, on March 14-18, or the conference — it’s re end me an email at

I hope this finds you well and in good health. If there is anything you need from NETA or want to see us do for the industry, send me an email at rwidup@shermco.com.

FIRST MEETING OF THE 70E 2018 CYCLE

BY RON WIDUP AND JIM WHITE, Shermco Industries

Much as the swallows return to Capistrano (see sidebar), so we returned to the 70E Technical Committee First Draft meeting. With all the approved changes made to the 2015 edition, initially we thought the number of Public Inputs (PIs) might be less for 2018, but that was not the case. The First Draft meeting was from Monday, August 17, through Friday, August 21, with different task groups meeting the weekend before to work out the details of individual sections. The last PI was finished on Friday at about 3:00 PM.

With PIs and a few Committee Inputs, the final count is still unknown. Several somewhat controversial issues are still on the table, including discussion surrounding the arc flash PPE tables [130.7(C)(15)(A)(a) and 130.7(C)(15)(A)(b)]. Table 130.7(C)(15)(A)(a) is moving to section 130.5 and is renamed Estimate of the Likelihood of Occurrence of an Arc Flash Incident for AC and DC Systems. In addition, the last column of the table heading that read Arc Flash PPE Required now reads Likelihood of Occurrence (Table 1). Also, the tasks have been reorganized and combined to make the table easier to use.

THE NFPA 70E AND NETA

Table 1: New Table 130.5(A) (Partial)

TABLE 130.5 ESTIMATE OF THE LIKELIHOOD OF OCCURRENCE OF AN ARC FLASH INCIDENT FOR AC AND DC SYSTEMS

Task

Reading a panel meter while operating a meter switch

Perform infrared thermography and other non-contact inspections outside the restricted approach boundary. This activity does not include opening of doors or covers

Work on control circuits with exposed energized electrical conductors and circuit parts, nominal 125 volts ac or dc or below without any other exposed energized equipment over nominal 125 volts ac or dc, including opening of hinged covers to gain access

Insulated cable examination with no manipulation of cable

For dc systems, insertion or removal of individual cells or multi-cell units of a battery system in an open rack

For dc systems, maintenance on a single cell of a battery system or multi-cell units in an open rack

Outdoor disconnect switch operation outside the arc flash boundary (hookstick operated) at 1 kV through 15 kV

Outdoor disconnect switch operation outside the arc flash boundary (gang-operated, from grade) at 1 kV through 15 kV

For ac systems: Work on energized electrical conductors and circuit parts, including voltage testing

For ac systems: Work on energized electrical conductors and circuit parts of seriesconnected battery cells including voltage testing

Removal or installation of CBs or switches

Opening hinged door(s) or removal of bolted covers (to expose bare, energized electrical conductors, and circuit parts). For dc systems, this includes bolted covers, such as battery terminal covers

Equipment

Application of temporary protective grounding equipment, after voltage test

Work on control circuits with exposed energized electrical conductors and circuit parts, greater than 120 V

Insertion or removal of individual starter buckets from MCC

Insertion or removal (racking) of CBs or starters from cubicles, doors open or closed

Insertion or removal of plug-in devices into or from busways

Insulated cable examination with manipulation of cable

Work on exposed energized electrical conductors and circuit parts of equipment directly supplied by a panelboard or motor control center

Insertion or removal of revenue meters (kW-hour, at primary voltage and current)

For dc systems, insertion or removal of individual cells or multi-cell units of a battery system in an enclosure

For dc systems, work on exposed energized electrical conductors and circuit parts of utilization equipment directly supplied by a dc source

Opening voltage transformer or control power transformer compartments

Outdoor disconnect switch operation inside the arc flash boundary (hookstick operated) at 1 kV through 15 kV

Outdoor disconnect switch operation inside the arc flash boundary (gang-operated, from grade) at 1 kV through 15 kV

Source: National Fire Protection Association 70E Committee

THE NFPA 70E AND NETA

Another change is placement of Table H.3(b) into section 130.5. Table 130.3(b) will be Table 130.5(D). It still appears in Annex H, but the committee wanted to bring more attention to this table. It is titled Selection of Arc-Rated Clothing and Other PPE When the Incident Energy Analysis Method is Used. One change made to the table is that the section for less than 1.2 cal/cm2 was removed, as this table only deals with arc-rated clothing; see Table 2 for a partial table.

Table 2: 130.5(D) (Partial)

TABLE 130.5(D) SELECTION OF ARC-RATED CLOTHING AND OTHER PPE WHEN INCIDENT ENERGY ANALYSIS METHOD IS USED

Incident energy exposures equal to 1.2 cal/cm2 up to 12 cal/cm2

Arc-rated clothing with an Arc Rating equal to or greater than the estimated incident energy (Note 1)

• Long-sleeve shirt and pants or coverall or arc flash suit (SR)

Arc-rated face shield and arc-rated balaclava or arc flash suit hood (SR) (Note 2)

Leather gloves or rubber insulating gloves with leather protectors (SR) (Note 3)

Hard hat

Safety glasses or safety goggles (SR)

Hearing protection

Leather footwear

Incident energy exposures greater than 12 cal/cm2

Arc-rated clothing with an Arc Rating equal to or greater than the estimated incident energy (Note 1)

• Long-sleeve shirt and pants or coverall or arc flash suit (SR)

Arc-rated arc flash suit hood

Arc-rated gloves or rubber insulating gloves with leather protectors (SR) (Note 3)

Hard hat

Safety glasses or safety goggles (SR)

Hearing protection

Leather footwear

Source: National Fire Protection Association 70E Committee

STRONG OPINIONS

The committee had strong opinions concerning the tables, but it reaffirmed the new format and put it into place for the 2015 edition of NFPA 70E. It also reaffirmed the deletion of the Prohibited Approach Boundary, although some committee members strongly wanted it back.

Another issue back from last cycle was changing the dc threshold from 50 V to 100 V. These issues (and a few more) generated some very lively discussions, which is actually good for the committee. These types of discussions made the NFPA 70E the document that it is today. None of us at NETA want a safety standard developed by a rubber stamp committee; rather, important issues should be discussed, and if needed, the merits and opinions debated completely and factually. This is an important safety standard, and all committee members feel strongly about making it the best it can be. And just to prove we were there, check out the photo of the 70E committee at the Schaumburg, Illinois, committee meeting.

2018 NFPA 70E Committee, Schaumburg, Illinois

THE NFPA 70E AND NETA

HOLD YOUR HORSES THERE, COWBOY

Sometime around March 2016, the First Draft will be published on the NFPA website (www.nfpa. org/70e) under the Next Edition tab. The committee will vote on its actions, requiring a two-thirds majority to approve it. At this last meeting, votes to approve some actions were pretty close, even though only a 51% majority is needed.

GET YOUR COMMENTS IN

Most of the PIs are from committee members. This is typical, but the committee needs to hear your voice. The next stage of the process is collecting any Public Comments, followed by the Second Draft meeting. The Public Comment period is open from when the First Draft is published on the NFPA website until May 16, 2016. We always hear from people in the industry how the 70E committee should change this or change that, and some of them have some really good ideas, but that is as far as it goes. The more input we have from the people using the 70E — especially from people within the NETA community — the better it will be.

SUMMARY

Major changes made to Article 120, sections 130.2, 130.4, 130.5, 130.7, and others are noted in the tables. We also had influence on some key maintenance-related content, and the overall document has been reorganized to give better flow to the standard and make it easier to use. And even though changes were made with good intent, sometimes words have unintended consequences; that’s where our NETA Accredited Companies and Technicians can really help out.

Point out the areas of concern before they become part of this standard; take a few minutes to write public comments and submit them. And test before touch!

THE SWALLOWS OF CAPISTRANO

The miracle of the Swallows of Capistrano takes place each year at Mission San Juan Capistrano on March 19th, St. Joseph’s Day.

As the faithful little birds wing their way back to the most famous mission in California, the village of San Juan Capistrano takes on a fiesta air, and visitors from all parts of the world and all walks of life gather in great numbers to witness the miracle of the return of the swallows.

At dawn on St. Joseph’s Day, the little birds arrive and begin rebuilding their mud nests, which are clinging to the ruins of the Great Stone Church of San Juan Capistrano. The arches of the two-story, vaulted Great Stone Church were left bare and exposed, as the roof collapsed during the earthquake of 1812.

The Great Stone Church, said to be the largest and most ornate of any of the missions, now has a more humble destiny — that of housing the birds that St. Francis loved so well.

After the summer spent within the sheltered walls of the Old Mission in San Juan Capistrano, the swallows take flight again, and on the Day of San Juan, October 23rd, they leave after circling the Mission, bidding farewell to the Jewel of the Missions.

Source: http://www.missionsjc.com/tours/swallows/

Ron Widup and Jim White are NETA’s representatives to NFPA Technical Committee 70E (Electrical Safety Requirements for Employee Workplaces). Both gentlemen are employees of Shermco Industries in Dallas, Texas, a NETA Accredited Company. Ron Widup is CEO of Shermco and has been with the company since 1983. He is a Principal member of the Technical Committee on “Electrical Safety in the Workplace” (NFPA 70E) and a Principal member of the National Electrical Code (NFPA 70) Code Panel 11. He is also a member of the technical committee “Recommended Practice for Electrical Equipment Maintenance” (NFPA 70B), and a member of the NETA Board of Directors and Standards Review Council. Jim White is nationally recognized for technical skills and safety training in the electrical power systems industry. He is the Training Director for Shermco Industries, and has spent the last twenty years directly involved in technical skills and safety training for electrical power system technicians. Jim is a Principal member of NFPA 70B respresenting Shermco Industries, NETA’s alternate member of NFPA 70E, and a member of ASTM F18 Committee “Electrical Protective Equipment for Workers”.

Ron Widup

Jim White

Absolute confidence. Every time.

You can count on us for specialized experience in healthcare, data center, office complex, and commercial acceptance and maintenance testing. Absolutely Power generation, petrochemical, oil & gas, and heavy industries also look to us for high demand services such as start-up commissioning, maintenance testing, shut-down and turnarounds, and breaker shop repair. Get started today.

Email: Alan Postiglione apost@absolutetesting.com

Primary

TRANSFORMER INSULATION

BY LYNN HAMRICK, Shermco Industries

Hartford Steam Boiler Insurance Company has been collecting information on transformer failures for years and periodically issues reports on the causes of such failures. Table 1 represents a compilation of those study results for 1975, 1983, and 1998. Note that “Deterioration of Insulation” was the second most frequent cause of transformer failure in 1998. This article will focus on internal failures of transformers, with a focus on the chemical processes that can cause insulation deterioration as well as how overloading and moisture accelerate the degradation process.

Basically, insulation within a transformer consists of cellulose (or paper) and insulating oil. A large amount of research has looked at the factors that affect cellulose and mineral oil. Cellulose ages and degrades through three basic chemical processes:

oxidation, acid-hydrolysis, and pyrolysis. These processes are caused by the presence of oxygen, the presence of water, and operating at elevated temperatures. The result is a weakening of the cellulose’s mechanical and electrical integrity, as well as sludging and contamination of the insulating oil.

OXIDATION

*Results of Hartford Steam Boiler Insurance Company studies on the causes of transformer failures.

Oxidation is defined as the interaction between oxygen molecules and all the different substances they may contact. Technically, oxidation is the loss of at least one electron when two or more substances interact. Those substances may or may not include oxygen. (Incidentally, the opposite of oxidation is reduction — the addition of at least one electron when substances come into contact with each other.) In a transformer, oil and paper degrade as a result of oxidation.

Table 1: Causes of Transformer Failures*

The most common insulating liquid used in transformers is mineral oil. Some transformer oils, referred to as uninhibited oils, possess a degree of natural protection against oxidation. However, mineral oil, which is known as inhibited oil, requires the addition of an antioxidant to protect against oxidation. For mineral oil, aging and oxidation are synonymous. The aging process begins slowly, as the antioxidants work to neutralize the harmful peroxides and radicals as they are formed. However, with time, the antioxidants decrease in quantity and the aging process increases exponentially. This leads to the formation of acids, aldehydes, ketones, esters, and eventually sludge (a mixture of long insoluble hydrocarbon molecules and particles). The process occurs in the presence of peroxides (unstable oxygen compounds) and free radicals and is accelerated by catalysts such as water and copper.

If allowed to continue, oxidized oil will continue to deteriorate and will transport contamination to the cellulose insulation within the transformer. Here the effects are much more serious. Transformer oil can be changed; unfortunately, cellulose cannot be changed. If the oil is not maintained, the condition of the cellulose will deteriorate to the point where the transformer has reached the end of its working life.

Cellulose degrades (oxidizes) much faster than oil because it contains oxygen within its molecular structure. The degradation process generates water, carbon dioxide, and furfurals, and is accelerated by external sources of oxygen, high temperature, and high levels of oil acidity. The water that is generated combines with dissolved moisture in the oil to further accelerate the degradation process. The end result is broken molecular chains, a lower degree of polymerization (DP), and loss of mechanical strength. In the absence of oxygen, decomposition occurs more slowly through the process of pyrolysis.

ACID-HYDROLYSIS

Acid-hydrolysis is the breakdown of the cellulose using H+ ions in water as a reactant.

In hydrolysis, a larger molecule, like molecules of cellulose, is broken down into simpler substances by the addition of water molecules. When this process is carried out in the presence of a small amount of acid, like that produced through the oxidation process, it is called acid-hydrolysis. The acid acts as a catalyst by providing H+ ions to facilitate the cellulose’s intake of water (H2O) molecules. To give an idea of the effects of water in the cellulose, it has been suggested that if the moisture content in cellulose doubles, transformer life expectancy is immediately halved.

PYROLYSIS

Pyrolysis is the breakdown of the cellulose at elevated temperatures. Simply stated, the higher the temperature the cellulose operates in, the faster the cellulose will degrade. Operating temperature increases can be the result of operating in overloaded conditions, some type of failure or limitation in the transformer cooling process, or elevated ambient temperature. Any of these situations can result in elevated temperatures of cellulose. It has been suggested that a thermal increase of just 10o C will lead to cellulose lifetime being cut by over 50%.

The best way to combat each of these degrading processes is to monitor transformer health by establishing a transformer maintenance routine and performing periodic oil analysis.

TRANSFORMER MAINTENANCE

The following should be monitored as part of regular transformer maintenance:

• Physical and mechanical condition. This should include an evaluation of the paint condition and cleanliness of the outside of transformer compartments and radiator cooling fins. Look at the LTC counter log and record the value. This inspection should also include a determination that no hindrance exists in getting air to the radiator cooling fins. Any suspected problem that could result in an oil leak or reduced system cooling should be recorded and brought to the attention of management for corrective action.

NICHE MARKET TESTING

• Oil leaks and spills. Oil seepage from within the transformer typically appears as a discoloration of the painted surface around a bushing or penetration. All suspected oil leaks should be recorded and brought to the attention of management for corrective action.

• Correct operation of cooling fans, if applicable. Transformer cooling fans are typically controlled with thermostats, turning on and off based on a temperature setting. If the fans are not running, it should be noted with the as-found thermostat settings recorded. The system should then be exercised by adjusting the thermostat settings to cause the system to operate. With subsequent operation, the thermostat settings should be returned to the original settings with the as-left settings recorded. If the system does not operate, this condition should be recorded and brought to the attention of management for a repair of the system.

MONITOR TRANSFORMER INDICATORS

Examination of these indicators is also part of transformer maintenance:

• Transformer temperature. For an OA 55/65 Class Transformer, operating temperature limits of the windings are 55o C or 65o C (131o F or 149o F, respectively), dependent on the kVA ratings of the transformer. Determine if the sensor is for top oil or winding temperature. It should be noted that the top oil temperature is probably lower than the winding temperature. Also, note the high temperature indicator and reset with each inspection.

• Transformer pressure. This measures the pressure of the nitrogen blanket above the oil. The gauge usually indicates negative and positive pressure. The pressure can vary from slightly negative to slightly positive due to ambient temperature and operating conditions. For sealed transformers, the

pressure should always be maintained at a slightly positive pressure. This is indicative of a proper seal and also ensures that moisture from the air does not leak into the nitrogen-filled gap at the top of the transformer.

• Transformer oil level. There is usually a mark on the gauge that indicates the 25° C level, which is the proper oil level for the transformer at that temperature. Maintaining the proper oil level is extremely important because if the oil level falls below the level of the radiator inlet, natural circulating flow through the radiator will cease and the transformer will overheat.

PERIODIC TRANSFORMER OIL ANALYSIS

The insulation system is typically evaluated by performing the following oil sample tests:

• Dielectric breakdown voltage. The dielectric breakdown voltage is a measurement of electrical stress that an insulating oil can withstand without failure. It is measured by applying a voltage between two electrodes under prescribed conditions under the oil. The dielectric test measures the voltage at which the oil breaks down, which is indicative of the amount of contaminant (usually moisture) in the oil.

• Moisture content. Oil moisture is measured in parts per million (ppm), using the weight of moisture divided by the weight of oil. Water can be present in oil in a dissolved form, as tiny droplets mixed with the oil (emulsion), or in a free state at the bottom of the tank holding the oil. Demulsification occurs when the tiny droplets unite to form larger drops, which sink to the bottom and form free water. When the moisture in oil exceeds the saturation value, there will also be free water precipitated from the oil in suspension or drops.

• Power factor. The power factor of insulating oil equals the cosine of the phase angle between an ac voltage applied and the resulting current. Power factor indicates the dielectric loss of the insulating oil, and thus, its dielectric heating. The powerfactor test is widely used as an acceptance and preventive maintenance test for insulating oil. A high power factor in service-aged oil indicates deterioration, contamination, or both, with moisture, carbon, or deterioration products.

• Interfacial tension. The interfacial tension (IFT) test is employed as an indication of the sludging characteristics of power transformer insulating oil. It is a test of IFT of water against oil, which differs from surface tension in that the surface of the water is in contact with oil instead of air. The attraction between the water molecules at the interface is influenced by the presence of polar molecules in the oil in such a way that the presence of more polar compounds causes lower IFT. The test measures the concentration of polar molecules in suspension and in solution in the oil, giving an accurate measurement of dissolved sludge precursors in the oil long before any sludge is precipitated.

• Acid neutralization number. The acid neutralization number, or acid number, is the amount of potassium hydroxide (KOH in mg) required to neutralize the acid in one gram of oil. It is indicative of the acid content in the oil. With service-aged oils, it is also indicative of the presence of contaminants, like sludge. The acidity test alone determines conditions under which sludge may form but does not necessarily indicate that actual sludging conditions exist. New transformer oils contain practically no acids. The acidity test measures the content of acids formed by oxidation. The oxidation products polymerize to form sludge, which then precipitate out. Acids react with metals on the surfaces inside the tank and form metallic soaps, another form of sludge.

• Color. The color of an insulating oil is determined by means of transmitted light and is expressed by a numerical value based on comparison with a series of color standards. It is recognized that color by itself could be misleading in evaluating oils for service quality. The primary significance of color is to observe a change or darkening of the oil from previous samples of oil from the same transformer. Noticeable darkening in short periods of time indicates either contamination or that arcing is taking place. A darkening color with no significant change in neutralization value or viscosity usually indicates contamination.

furanic acids

As the transformer ages, the sampling program should also include checking for the oxygen inhibitor level. Oxygen inhibitors should be in the oil at acceptable levels, which is typically in the 0.3% to 0.4% range. DBPC, 2,6-ditertrybutyl-paracresol, is the most commonly used antioxidant, but there are many types. As you monitor depletion rates, note the type and level for future reference. Additionally, furanic acids should be monitored when you have other indicators that the cellulose has degraded. When cellulose insulation decomposes due to overheating, chemicals are released and dissolve in the oil.

Transformer insulation is degraded by the presence of oxygen or water , and by operation at elevated temperatures.

er indicators that has ose insulation decomposes due to chemicals are released and dissolve

ical are known as ounds, acids, or furans. In no detectable furans are in the b). As the cellulose the indicate accelerated cellulose evels risk

These chemical compounds are known as furanic compounds, acids, or furans. In healthy transformers, no detectable furans are in the oil (<100 ppb). As the cellulose degrades, the furan levels will increase. Furan levels of 500 ppb to 1,000 ppb indicate accelerated cellulose aging; furan levels >1,500 ppb have a high risk of insulation failure.

With regard to performing dissolved gas analysis (DGA) and using the results for evaluating

o dissolved analysis using the results for

NICHE MARKET TESTING

cellulose and insulating oil degradation, the ratio of CO2/CO can be used as an indicator of the thermal decomposition of cellulose. The rate of generation of CO2 typically runs seven to 20 times higher than CO. Therefore, it is normal if the CO2/CO ratio is above seven. If the CO2/CO ratio is five or less, there is probably a problem. If cellulose degradation is the problem, CO, H2, methane (CH4), and ethane (C2H6) will also be increasing significantly. At this point, additional furan testing should be performed. If the CO2/CO ratio is three or under with increased furans, severe and rapid deterioration of cellulose is occurring, and consideration should be given to taking the transformer out of service for further inspection.

REFERENCES

A Guide to Transformer Maintenance, S. Myers, J. Kelly and R Parish (ISBN-13 978-0939320004)

IEC 60076-14 ed 1.0 (September 2013) Power Transformers – Part 14: Liquid-Immersed power transformers using high temperature insulation materials.

Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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SUNSHINE, SEA, AND BLUE SKIES GREET NETA MEMBERS IN SEATTLE, WASHINGTON

BY KRISTEN WICKS, NETA

September brings chillier air, shorter days, and an opportunity for NETA Accredited Company members to gather at one of their regularly scheduled Board of Directors and Member meetings. This fall, meeting attendees gathered in along the Pacific shoreline to discuss the coming months of association business. PowerTest is right around the corner, and there are exciting things in the works when it comes to member services, communications, and the technical exam.

The Board of Directors is constantly assessing the strategic direction of the association, and assuring that the programs, services, and budget are in alignment with the vision for the future while adhering to the foundation of the past. NETA members enjoyed a long

technical exchange in the wake of many code committee meetings that also mark this season. There was also time for additional idea generation with regard to PowerTest and what tweaks can be made there to make it an even more excellent event.

Everyone also made time to share in fellowship over meals, cocktails, and outings around the city. If you have never been to Seattle – go! It is beautiful. If you have never been to a Member meeting, were just at this last one, or haven't been in a while – come! The next one will be in January 2016 in Key West, Florida, and we would love to see you there. Contact the NETA office for more details.

James R. (Jim) White is the Training Director of Shermco Industries, Inc., in Dallas, Texas. He is the principal member on the NFPA technical committee

“Recommended Practice for Electrical Equipment Maintenance” (NFPA 70B). Jim represents NETA as an alternate member of the NFPA Technical Committee “Electrical Safety in the Workplace” (NFPA 70E) and represents NETA on the ASTM F18 Committee “Electrical Protective Equipment For Workers”. Jim is an IEEE Senior Member and in 2011 received the IEEE/PCIC Electrical Safety Excellence award. Jim is a past Chairman (2008) of the IEEE Electrical Safety Workshop (ESW).

POWER TRANSFORMERS

BY JIM WHITE, Shermco Industries

Power transformers have no moving parts (except for accessories such as fans, pumps, or LTCs), and yet, they are very complex electrical devices. This month’s Tech Quiz asks questions on general power transformer knowledge — some from the MTS, some not. Let’s see how you do:

1. Power transformer cooling designations underwent changes a few years ago. Match up the old designation with the new:

a. FA ONAF/ODAF

b. FOA ONAN

c. OA/FOA ODAF or OFAF

d. OA ONAF

2. Buchholz relays are used on transformers to detect:

a. Winding over temperature

b. Over pressure of tank

c. Change in oil temperature

d. Internal faults

3. Sudden pressure relays operate on a:

a. Rapid increase in main tank

b. Pressure set point in lbs/in2

c. Difference in pressure between main tank and tap changer tank

d. Rapid increase in conservator pressure

4. What type of sensing element can measure a transformer’s hottest-spot (winding) temperature directly?

a. Fiber optic cable

b. Thermocouples

c. Platinum RTDs

d. Oil well monitor

5. Hydrogen is often the primary gas used for field monitoring of combustible gases. Check all the answers that apply:

a. Hydrogen is the smallest molecule, so it passes through membranes when others won’t.

b. Hydrogen can be tinted to make it more visible, allowing easier detection by optical sensors.

c. Hydrogen is always present when combustible gases are generated.

d. Hydrogen has a distinct odor, allowing the use of olfactory detectors.

No. 112

CASE STUDY: OF SOURCES USING MULTIPLE SENSORS LOCATION GENERATOR PD

BY DON A. GENUTIS, Halco Testing Services

Generator health is one of the single most critical elements of a power-producing operation's ability to maintain a reliable revenue stream. These generators typically operate at medium voltage levels; thus, a high percentage of overall failures are attributed to insulation defects, as is often the case in any medium voltage equipment.

Statistics from IEEE and EPRI studies indicate that approximately 37% of generator failures can be attributed to stator insulation failure. Stator insulation deterioration can be tracked by regular partial discharge (PD) testing or continuous monitoring methods. The importance of monitoring the generator's insulation for PD activity — along with monitoring other common mode failure components such as bearing condition — is a widely accepted practice in North America. This article will briefly address the general application of multiple generator partial discharge sensors and then discuss a recent event where the sensors predicted an impending failure.

SENSOR APPLICATION

Permanent coupling capacitor sensors can be used to detect generator discharges by connecting a sensor to each bus phase at an accessible location near the generator. The coupling capacitors provide a means of obtaining consistent and calibrated signals. At least one generator monitor manufacturer also uses the generator's existing RTDs to detect PD.

Figure 1: Coupling capacitor shown far left only provides winding coverage to area circled in green, while the RTDs provide coverage to areas circled in blue. Collectively, the use of the coupling capacitor and RTD sensors provide much greater coverage than just the coupling capacitor alone.

Although the RTDs cannot always provide a calibrated signal, they can be useful for detecting PD deeper in the generator windings, as much as 60-70%, whereas the coupling capacitor typically can only see the first 15% of the windings (Figure 1).

Since the ISO-phase bus can also discharge, an additional set of coupling capacitors should be placed on the bus further away from the first set of sensors to detect the direction of the arriving PD pulses via the time-of-flight method (Figure 2).

A more convenient and cost effective method is to use a set of high frequency CT sensors on the ISO phase ground straps to determine source origination (Figure 3).

Studying individual PD pulse characteristics such as frequency and polarity may assist in determining the likely physical discharge location and the type of discharge occurring.

CASE STUDY

A customer operating a large steam generator experienced a sudden high increase in Phase A PD magnitude discharge (Figure 4).

The high-frequency characteristics of the pulse indicated that the discharge was occurring near the sensors, and the ringing characteristics indicated a surface or interface discharge (Figure 5).

Figure 5: Typical Signal Pulse Displaying High Frequency Ringing Characteristics Indicative of Local Surface Activity

Figure 2: Time of Flight Method Used to Determine Signal Origination

Figure 3: Signal Origination Using HFCT

Figure 4: Dramatic Signal Amplitude Increase

The polarity indicated that the PD source was originating from the ISO phase bus (Figure 6).

The diagnosis: early stages of surface tracking of Phase A ISO Phase insulator located near the vicinity of the PD couplers.

The engineering department planned an immediate outage, and the inspection revealed excessive moisture occurring in Phase A ISO Phase bus (Figures 7, 8, and 9), resulting in early stage surface insulator tracking. This was precisely the same conclusion as diagnosed by the analysis of the PD pulses. Simple repairs were conducted during the outage, and the generator was brought back on line, thereby averting a potential catastrophic failure.

Figure 6: Using Pulse Polarity to Determine Signal Origination

Figure 7: Moisture Accumulation on ISO Phase Insulator

Figure 8: Moisture Presence on ISO Phase Insulation Component

CONCLUSION

Figure 9: Insulator Moisture Accumulation and Early Stages of Tracking Damage Due to Discharge Activity and Corrosion Due to Nitric Acid Byproducts

Generator PD monitoring allows tracking of the insulation condition and can provide an early warning of impending failure, thus positively impacting reliability.

Don A. Genutis holds a BSEE from Carnegie-Mellon University. He has over 30 years of electrical testing experience. Don serves as President of Halco Testing Services based in Los Angeles, California.

Figures 1, 2, 6 courtesy of Dynamic Ratings © Dynamic Ratings Inc., all rights reserved.

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COMMISSIONING STANDARDS

BY LORNE GARA, Orbis Engineering Ltd.

NETA has developed a new electrical testing standard called the ANSI/NETA ECS-2015 Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems (NETA ECS).

No matter what type of industry sector you are in, when it comes to electrical power equipment, it is important to understand the processes and procedures that take place from a system’s initial concept to final acceptance and energization at your facility. Regardless of the industry — whether it is a steel mill, refinery, paper mill, electrical utility, data center, hospital, commercial building, etc., — all require the individual pieces of electrical equipment to interconnect with each other and work together as a system to assure safety and reliability.

Commissioning is the systematic process of verifying, documenting, and placing into service newly installed or retrofitted electrical power equipment and systems. Commissioning is critical for all new or retrofit installation projects to verify the correct system operation to the design, which contributes to the safe and reliable operation of the system.

NETA recognized that electrical commissioning has not been well defined in the industrial and utility markets, though a greater degree of documentation and guidance exists within the building and health facility sectors. This was one motivation for NETA to develop an electrical commissioning specification that can be applied on a global basis to many industries, and thus the NETA commissioning standard was developed and approved as a consensus-based standard.

OTHER COMMISSIONING STANDARDS

A number of commissioning standards have been published to date.

• ASHRAE Guideline 0. Published by the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE), this standard defines the commissioning process for building systems. It presents best practices for applying whole-building commissioning to facilities.

• ASHRAE Guideline 202. Published by the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE), this guideline describes how to plan, conduct, and document the commissioning process for buildings and systems.

• NECA 90 – Recommended Practice for Commissioning Building Electrical Systems. Published by the National Electrical Contractors Association, this document describes the procedures for commissioning building electrical systems.

• NIBS Guideline 3 – Building Enclosure Commissioning Process BECx. Published by the National Institute of Building Sciences (NIBS), this standard describes a process that allows an owner to incorporate building enclosure commissioning into a project and is used in conjunction with the ASHRAE Guideline 0.

In addition to the above standards, a number of other commissioning standards can be found in reference to building systems, fire alarm systems, and health facilities. Some of the publishers are ASHRAE, NIBS, NECA, NFPA, ASHE, CSA, and ASTM.

All of the commissioning standards emphasize the importance of commissioning and using an independent third-party testing and commissioning company; however, a considerable difference of opinion exists regarding the definition of commissioning and the processes involved. The commissioning industry is continually evolving, and the commissioning process may involve multiple trades and systems. It is important for the Commissioning Agent to help determine and document the Owner’s Project Requirements (OPR) so they can be used in all stages of the project. The OPR is the focus of the commissioning activities and should include the applicable standards for the project. This could be one standard or multiple standards. The Commissioning Agent should be under direct contract to the owner and have a direct line of communication to the owner.

The commissioning standards currently available are specific either to a business sector or to equipment type. The ANSI/NETA ECS was not developed to replace any of the existing standards. Rather, it was developed for use on any new or retrofit electrical installation projects and can be applied on a global basis to many industries. It describes the commissioning process and the tasks to help the commissioning team develop, execute, and document the commissioning process for electrical power equipment. The ANSI/NETA ECS is a commissioning standard specific to electrical power equipment and systems. It can be used alone or in conjunction with other applicable commissioning standards. In comparison to other available standards, the ANSI/NETA ECS has

unmatched detail of the commissioning process for electrical power equipment.

As today’s systems become more complex, the need for standards, processes, plans, and documentation is increasingly important for commissioning personnel. NETA recognized the need for a commissioning standard specific to electrical power equipment and published the ANSI/NETA ECS Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems. NETA is currently working with other standard organizations to define the commissioning process and align the standards. Many of the other standard developers recognize NETA’s efforts and reference the ANSI/NETA documents in their publications.

SUMMARY

By defining the commissioning process, the commissioning standards will help guide the owner and the commissioning team to work together to develop and execute the commissioning plan. Note that the commissioning work starts early in the project and continues throughout the project. Fundamental documents such as the OPR are valuable tools that should be the focus of commissioning tests. All applicable commissioning and testing standards should be used together to accomplish the commissioning project.

Regardless of the system complexity or size, create a commissioning team early in the project

(ideally in the pre-design stage) and include the applicable commissioning standards. If the system has electrical equipment, one would certainly want to include the ANSI/NETA ECS Standard for Electrical Commissioning Specifications for Electrical Equipment and Systems, since the systems are complex and require specialized personnel to perform the inspections, tests, and commissioning. Testing and commissioning personnel should be part of an independent third-party organization that is selected based on its certification, experience, knowledge, and specialization. The commissioning agent should be under direct contract to the owner and have a direct line of communication to the owner.

Understanding the full scope of commissioning activities is the first step in obtaining the greatest value of the commissioning process and assuring the safe and reliable performance of your system.

Lorne Gara is a Technical Manager for Orbis Engineering. He provides technical support for the engineering, field services, and automation departments of Orbis and many of its clients. Gara has a wide range of experience in engineering, commissioning, maintenance, fault analysis, and the startup of utility and industrial power systems across North America. He has extensive experience with protective relay setting development, commissioning, and testing of protection and control systems.

National Field Services, a NETA-accredited electrical testing company, is now offering training courses on a range of safety and technical topics at our National Training Center in Lewisville, Texas. Our instructors can also conduct most courses at your facility, on your schedule. Find our Course Catalog and more information at natlfield.com/training or contact Training Program Manager Steve Newton at steve.newton@natfield.com or 469-312-1230. 800-300-0157 natlfield.com/training

Relevant information the electrical power systems industry, from testing procedures and troubleshooting to encountered in the field. It’s real world learning at your fingertips.

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GROUNDING PERSONAL PROTECTIVE

BY JEFF JOWETT, Megger

Grounding protection for electrical workers depends on both good practice and proper protective equipment and materials. Fortunately, standards covering both areas have been written and published. Carelessly rigged protective equipment may not carry sufficient current, offer too high a resistance, burn open, or subject a worker to numerous other dangerous conditions. A prime authority in describing and specifying safe grounding equipment is The American Society for Testing and Materials (ASTM), Committee F-18, Electrical Protective Equipment for Workers, which is responsible for ASTM Document F-855, Standard Specifications for Temporary Protective Grounds to Be Used on De-energized Electric Power Lines and Equipment.

A common piece of protective equipment is the grounding jumper, which is designed to safely divert fault current by means of a continuous low-impedance path around the worker. Personal protective grounding jumpers are made up of appropriate lengths of suitable copper grounding cable with mechanically compatible ferrules and clamps at each end. Note that simply applying what is conceived as a dead short across a prospective voltage gradient does not constitute an adequate protective ground. It is instructive to reconsider a protective jumper’s current, which includes the surface contact resistance between the clamp and the conductor being jumpered. (Editor’s note: See the previous article in this series, NETA World Journal, Fall 2015.) Both the clamp and the jumper wire have a resistance, as does the second clamp and surface contact resistance at the other end.

Even though these individual resistances are very small, they can add up to a significant voltage drop at rated short-circuit duty. They do this by creating an equipotential zone, with grounds applied in such a manner that the employee’s hands, feet, and body are at the same potential as the equipment worked upon.

Design, installation, and assembly criteria for equipotential grounding jumpers:

• Must have sufficiently low resistance.

• Be capable of conducting maximum fault current, which could occur from the circuit or equipment becoming energized from any source, and will not burn open under the stress of maximum current flow, thus leaving the worker unprotected.

• Have clamp terminations suitable for conducting maximum fault current as well

as providing a mechanical connection that can withstand the forces generated by electromagnetic induction.

• Use minimum time and preparation for installation.

• Cover a wide range conductor sizes, buss bars, ground wires and ground rods, and structural steel.

• Be easy to apply and amenable to all prospective field conditions.

grounding and what may be considered traditional jumpering is illustrated in Figures 1, 2, and 3. If the worker is separately grounded in parallel with the jumper (Figure 1), the difference between normal body resistance and that of the jumper is substantial. Such an arrangement provides a path for induced voltage dissipation, and the circuit can clear a breaker. But the worker can still develop a potentially fatal voltage across the body, as RG2 — the resistance of the worker’s ground return path — exceeds that of the jumper, RG3 (Figure 2).

During installation, the ground-end clamp is connected first. This assures there is no time during installation, however brief, in which the operator could become the lowest-resistance ground path.

Similarly, the conductor-end clamp should be connected and disconnected with hot-line tools, using sticks of appropriate length for the system voltage, in the event that the conductor becomes live during connection or disconnect. However, in many utilization and low-voltage distribution systems, it is physically impossible to use hotline tools for application of grounds. Therefore, additional shock and arc protective equipment are imperative for worker protection.

An equipotential zone is created when grounds are situated such that the hands and feet of the worker are kept at the same potential. The worker has the same ground return path as the grounding conductor rather than a parallel path of differing potential. The difference between equipotential

The difference in equipotential jumpering is that only one ground return path (RG3) exists (Figure 3). In this case, when the circuit is inadvertently energized, the worker and the grounding jumper are truly in parallel. The return circuit does not employ a separate path through the earth, and therefore, does not include the worker’s body resistance. Rather, the combination of the low resistance of the grounding jumper and the relatively high body resistance of the worker in the same grounding path produces a very low voltage drop across the worker. This technique is commonly referred to as Single Point Grounding. The voltage

Figure 1: Worker Separately Grounded in Parallel

Figure 2: Incorrectly Jumpered Worker

Figure 3: Equivalent Circuit Correctly Jumpered

drop across the worker becomes a function of fault current through the personal protective jumper and can be determined by the equation:

Vworker = R jumper x I jumper

Typical equipotential grounding techniques are illustrated in Figure 4 and Figure 5.

As mentioned, the successful accommodation of maximum fault current by the grounding jumper is critical in maintaining this protection. Accordingly, personal protective grounding

jumpers must be tested and maintained in adequate working condition. Such jumpers can be subject to considerable electrical stress during fault events, in addition to the usual physical stresses associated with installation and removal. Mere visual inspection and assumptions about internal conditions are not enough to ensure that the jumper is fully protective of the worker’s safety. It should be electrically tested for low impedance to limit voltage drop on the worker. Testing should be done with current injection of the continuous rating of the conductor. Voltage drop of the grounding jumper can be calculated with the formula:

I test /I sca = V test /V sca

I test is the continuous current rating of the grounding conductor jumper. Isca is the maximum available short circuit current of the system where applied. Vtest is the measured voltage drop during the test. V sca is the calculated voltage drop during a fault condition.

It is also recommended that an infra-red (IR) scan of the jumper is performed under rated load current. This will reveal if any “hot spots” or areas of weak bonds or localized high resistance exist that might fail and burn open under the stress of a fault condition. Another valuable test is a low-resistance ohmmeter test with at least 10 amps. The test result is compared to a maximum acceptable value for the rating of the jumper.

Although not all equipment is required to be grounded, it is an industry-accepted recommendation that work on de-energized equipment and circuits is performed with visible protective grounds and jumpers in place at the site. Industry-standard procedures for the placing and removing of such grounds have been devised. Remember that these are generic and not intended to replace specific working practices for particular industries.

Step 1: De-energize the line in accordance with procedures. Use a documented procedure to be certain that the circuit or equipment has been de-energized and isolated from all sources of hazardous energy.

Figure 4: Equipotential Zone

Figure 5: Effectively Applied Grounding Jumpers

Step 2: Test the circuit for voltage. Don’t assum that the circuit has been de-energized just becau it’s been turned off. Other sources of energy, such as induction from nearby circuits, can produc injurious or lethal shocks.

Step 3: Clean connections. Remember, Singl Point Grounding is effective because the worke body is in parallel with an extremely low resistanc to ground. To maintain that low resistanc extraneous resistances from corrosion and di should be scrupulously eliminated.

Step 4: Apply ground-end clamps first, and remove them last.

Step 5: Conductor-end clamps must be applied and disconnected by hot sticks of adequat rating and length.

atcle thssees.

Step 6: Remove in reverse order from installation. The details of these six steps will be described and elaborated, and various extraneous sources of dangerous voltages — such as induction, static, capacitive and electromagnetic coupling, and other dangers — will be dealt with in the last in this series.

Jeffrey R. Jowett e is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation He e holds a BS in Biolog y and Chemistrry y from Ursinus College. He was employed for r 22 y years with James G. Biddle Co. which became Biddle Instruumennts and is now Megger.

ource: AVO Training Institute, Dallas, Texas

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SAFETY CORNER PO WER TRANSFORMER HAZARD AWARENESS

O

BY SCOTT BLIZARD,

Performing a condition analysis or maintenance on a power transformer and auxiliary devices is a hazardous task that requires an experienced individual with a solid ability to identify potential hazards and mitigate risks.

Condition analysis of a power transformer may be performed using methods and products designed to test and diagnose the equipment when it is operating, such as infrared survey, partial discharge detection equipment, and online oil analysis. The Personal Protective Equipment (PPE) required should be appropriate and adequate for all tasks performed.

This article is an overview of some of the potential hazards of a power transformer and various means of safeguarding as well as mitigation of those hazards. This article does not include every potential hazard, but rather, explores some potentially hazardous situations that can occur while performing work on a power transformer and auxiliary equipment. Additional hazards may exist, depending on the type or condition of the equipment. Take all procedures and instructions seriously, and verify that the instruction or equipment operation and maintenance manuals used are for the correct equipment. Check for and identify potential hazards prior to beginning every task by using a Pre-Job Brief worksheet.

ELECTRICAL AND MECHANICAL HAZARDS

Improper Lock Out/Tag Out (LO/TO) is a major contributing factor to injuries caused by power

transformers and auxiliary devices. Controlling hazardous energy is essential, and many forms of energy may be involved. To determine the proper LO/TO procedures, always refer to the appropriate OSHA regulation or required procedure, such as 29 CFR 1910.147 and .333, as well as manufacturer instructions. Electricity is the most obvious hazardous energy source.

Electrically de-energize the power transformer and auxiliary devices from their primary energy source and ensure the equipment is disconnected from all sources of power, both ac and dc, if applicable. Once de-energized, verify that the equipment is at a zero energy state using the manufacturer’s approved method. Verify the accuracy of the detection or voltage measuring device against a known source, check for zero energy on the de-energized equipment, and then test the detection equipment against a known source again. This will verify that the detection meter used was functioning properly during the initial check. Testing for voltage will require its own level of PPE, depending both upon the voltage level and arc-flash hazard level and test procedures per NFPA 70E 2015 — Standard for Electrical Safety in the Workplace or OSHA 29 CFR 1910.269 — Electric Power Generation, Transmission, and Distribution regulation.

American Electrical Testing Co., Inc.

Electrical energy isn’t the only energy that requires LO/TO. Devices such as motoroperated switches and circuit breakers and others may contain a large amount of mechanical energy. This energy must be dissipated prior to servicing the equipment or serious injury could occur. Once the energy has been discharged or dissipated, LO/TO the source of the stored energy, if feasible. Ensure that remote operating handles are tagged in a local or manual mode. This will prevent someone from inadvertently operating the equipment.

CHEMICAL HAZARDS

Certain types of power transformers may also pose a chemical hazard; take caution with gases, chemicals, and liquids. Use proper containment of liquids (e.g. spill containment pads) and address environmental concerns. Ensure compliance with all owner, state, and federal regulations. Beware of units containing Polychlorinated Biphenyls (PCBs) or other hazardous fluids. When working on such units, follow appropriate state and federal guidelines for fluid handling and disposal, and avoid skin contact.

Some cleaners may pose a respiratory and skin irritant if used in enclosed areas or on bare skin. Gain knowledge of the material and check the applicable Safety Data Sheet (SDS) to identify any potential health effects from its use. Once again, proper PPE is necessary for using some cleaners; for example, nitrile gloves, safety glasses, face-shield, and even respiratory protection may be needed.

SAFETY CORNER

Transmission, and Distribution regulation, or is it a commercial entity or space regulated under OSHA 1910.146 (permit-required confined spaces regulation)? These OSHA regulations have different requirements, depending on the location of the space and its hazards.

OSHA has created a flow chart to help with that determination, located within OSHA 1910.269 Appendix A. This flow chart is shown in Figure 1 and can also be viewed at http://tinyurl.com/ p329zxo.

CONFINED SPACE

Figure 1: Appendix A-5 to §1910.269 — Application of §§1910.146 and 1910.269 to Permit-Required Confined Spaces

When performing the visual inspection, mechanical inspection, maintenance, or repairs on a power transformer, personnel may be required to enter the actual tank. Entering into a confined space requires the entrant to be aware of the conditions within that space. The entrant needs to first ask: Is this confined space located at a facility regulated by the OSHA 1910.269 Electric Power Generation,

To answer the questions on the flow chart, the entrant must know the following from the OSHA regulations.

1. OSHA 1910.146(b) defines a confined space.

a. “Confined space” means a space that:

(1) Is large enough and so configured that an employee can bodily enter and perform assigned work;

(2) Has limited or restricted means for entry or exit (for example, tanks, vessels, silos, storage bins, hoppers, vaults, and pits are spaces that may have limited means of entry.);

(3) Is not designed for continuous employee occupancy.

2. OSHA 1910.146(b) describes when the confined space requires a permit to enter.

a. “Permit-required confined space (permit space)” means a confined space that has one or more of the following characteristics:

(1) Contains or has a potential to contain a hazardous atmosphere;

(2) Contains a material that has the potential for engulfing an entrant;

(3) Has an internal configuration such that an entrant could be trapped or asphyxiated by inwardly converging walls or by a floor which slopes downward and tapers to a smaller cross-section;

(4) Contains any other recognized serious safety or health hazard.

3. The entrant must know if the work to be performed falls under the scope of the 1910.269 regulation — put simply, if that work is conducted during the operation and maintenance of electric power generation, control, transformation, transmission, and distribution lines and equipment. Specific information on that definition may be found in all of 1910.269(a)(1).

4. The entrant must also determine if, under 1910.269, the space is considered an “enclosed space.”

a. Enclosed space: A working space, such as a manhole, vault, tunnel, or shaft, that has a limited means of egress or entry, that is designed for periodic employee entry under normal operating conditions, and that, under normal conditions, does not contain a hazardous atmosphere, but may contain a hazardous atmosphere under abnormal conditions.

b. Note to the definition of “enclosed space”: The Occupational Safety and Health Administration does not consider spaces that are enclosed but not designed for employee entry under normal operating conditions to be enclosed spaces for the

purposes of this section. Similarly, the Occupational Safety and Health Administration does not consider spaces that are enclosed and that are expected to contain a hazardous atmosphere to be enclosed spaces for the purposes of this section. Such spaces meet the definition of permit spaces in §1910.146, and entry into them must conform to that standard.

5. The entrant must also know the potential hazards within the space that must be controlled prior to entry in a 1910.269 regulated enclosed space. For more information regarding those hazards, see all of 1910.269(e).

OTHER PHYSICAL HAZARDS

When performing the visual inspection, mechanical inspection, maintenance, or electrical tests on a power transformer, gravity is an energy that may also need to be controlled. The size and weight of panel covers and inspection plates may make them difficult to handle. Should gravity be a potential energy source, ensure that the energy is dissipated and controlled as part of the LO/TO procedure.

IMPROPER PPE HAZARDS

After verification that the power transformer is de-energized, the method of disconnecting the equipment may require a different form or class of PPE. Ensure that proper PPE is used for the class of disconnecting means. Refer again to the NFPA 70E 2015 or OSHA 1910.269. They will indicate what level of protection is required, depending on the task and within certain levels of exposure. Identifying the correct level of PPE and gloves will aid in the mitigation of injury from a potential arc flash. However, the table within NFPA 70E only provides information based on known values of the short circuit current available, the clearing time in cycles, and minimum working distance. If those factors are unknown, more information must be gathered prior to performing the work to ensure personnel safety.

Table 1: NFPA 70E 2015 Table 130.4(D)(a)) — Approach Boundaries to Energized Electrical Conductors or Circuit Parts for Shock Protection for Alternating Current Systems

Note 1: For arc flash boundary, see 130.5(A).

Note 2: All dimensions are distance from exposed energized conductors or circuit part to employee.

a. For single-phase systems, select the range that is equal to the system’s maximum phase-to-ground voltage, multiplied by 1.732.

b. See definition in Article 100 and text in 130.4(D)(2) and Annex C for elaboration.

c. Exposed movable conductors describe a condition in which the distance between the conductor and a person is not under the control of the person. The term is normally applied to overhead line conductors supported by poles.

d. This includes circuits where exposure does not exceed 120V.

Table 1 provides the approach boundaries from NFPA 70E. It indicates at what proximity to the alternating-current, energized equipment that the PPE must be donned.

Again, the PPE must be adequate for the task and energy levels, and worn prior to entering within the Restricted Approach Boundary.

Additional tables exist for direct-current energized equipment.

INSTALLATION OF TEMPORARY PROTECTIVE GROUNDS

Grounds are an excellent secondary means of protecting the worker from inadvertent

energization. Refer to any applicable OSHA regulation such as 29 CFR 1910.269, NFPA 70E, and ASTM F855 for specific guidance on grounding locations and sizing of grounds required for the task.

Grounds must always be applied upstream and downstream of the equipment and as close to the work as possible. Using correctly sized and applied grounds is an additional safeguard for employees should there be a form of electrical energy introduced into the system or equipment being worked on. Induced voltage or backfeed are just two forms of energy that may be inadvertently introduced into a system that has been properly Locked Out/Tagged Out.

SAFETY CORNER

IN CONCLUSION

When performing maintenance and testing on a power transformer, take care of the following:

1. Obtain all service bulletins, maintenance documents, arc-flash studies, and manuals prior to working on that specific device.

2. Review all prints and one-lines associated with the equipment.

3. Establish a safe work area, and barricade off the work area.

4. Perform a pre-job brief with all employees on-site.

5. Wear proper PPE.

6. Disconnect the electrical feed and control circuit(s), verify mechanical interlocks are properly engaged, and test equipment before performing visual or mechanical inspections.

7. If applicable, verify that there is zero energy (test, check, test), and discharge all

stored energy, including pressurized gasses and gravity.

8. Complete the Lock Out/Tag Out (for all energy sources).

9. Connect grounds where and /if applicable.

10. Identify, visually mark, or flag the equipment being worked on.

Being aware of and mitigating the hazards listed here can lead to a safer work environment while performing inspection, maintenance, and testing of a power transformer.

Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician.

MODERN ADVANCES IN TESTING MULTIFUNCTION

NUMERICAL TRANSFORMER PROTECTION RELAYS

BY STEVE TURNER, Beckwith Electric Company, Inc.

This article demonstrates different techniques to test multifunction numerical transformer protection relays, so that these techniques can easily be incorporated into automated test software. The Common Format for Transient Data Exchange (COMTRADE) for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays because it can replay actual operating conditions or simulate a very complex event such as transformer energization when there is remnant flux on the core of a winding.

The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using the Electromagnetic Transient Program (EMTP). Lastly, automated testing of the boundary of the phase differential operating characteristic is illustrated to properly test the relay settings.

COMTRADE SIMULATION –2 ND HARMONIC RESTRAINT ON INRUSH

COMTRADE records captured by numerical relays and digital fault records from actual system events are of particular interest since these provide the ability to test protection for critical faults or disturbances that are

difficult to create using off-the-shelf, test-set software. Utilities, consultants, and equipment manufacturers can build a library of test cases. The first example is the case of transformer differential protection operating during energization due to low 2nd harmonic current content in the inrush current. This event was recorded by the numerical relay protecting a 400 MVA 230/115 kV autotransformer that was energized from the high side while the low side was open (Figure 1). The auto-transformer is connected to a 230 kV straight bus through a motorized disconnect switch. The CTs are wyeconnected on both sides. The 230 kV CTs are on the transformer bushings connected with the full ratio (1200:5).

Figure 1: Auto Transformer High Side Energization

This is an excellent case to use the COMTRADE record captured by the relay since you can test transformer differential protection to ensure it does not operate during inrush for many applications —that is, most two-winding transformers and auto banks with five-amp, secondary-rated CTs on the high side.

Figure 2 shows very little restraint current and high magnitude differential current in B Phase during the transformer energization. The trip occurred when the ratio of B Phase 2nd harmonic to fundamental current dropped too low.

The relevant current phasors measured by the relay at the time of the trip along with the 2nd harmonic contents are listed in Figure 3.

The numerical transformer differential relay that tripped uses internal zero-sequence current compensation to prevent unwanted operations during external ground faults since the current transformers are wye-connected, and the transformer is an auto bank. Calculating the phase-to-phase current automatically eliminates zero-sequence current as follows: I

If the transformer differential relay uses phaseto-phase current to eliminate zero-sequence current, then Ibc is the most depleted of 2nd harmonic content and also corresponds to the phase that actually tripped (B-Phase). Figure 4 illustrates the following signals:

• Ibc

• Fundamental component

• 2nd harmonic component

• Ratio of 2nd harmonic to fundamental

The ratio decreases in magnitude over the first two cycles following energization. The relay tripped at the point when the ratio dropped to

Figure 2: High Side CT Secondary Fundamental Versus 2nd Harmonic Current

Figure 3: Current Phasors Measured at the Relay with 2nd Harmonic Current

14%. Note that transformer differential relays are typically set to restrain at 15%. Figure 4 illustrates how the phase differential protection is restrained using 2nd harmonic current. Ratio = diff

Figure 4: Current 2nd Harmonic Restraint Logic

Figure 5: Current Phasors Measured at the Relay with 2nd and 4th Harmonic Current

Test

Requirements

You will need a three-phase test set that can playback COMTRADE records. Three current channels are required. Connect the three-phase test set to the relay as shown in Figure 6A.

Figure 6A: Test Connections

Figure 6B shows off-the-shelf software available to play back this particular COMTRADE record through the test set to the relay.

Figure 6B: Test Connections

TEST PROCEDURE

1. Play back the inrush case to the relay with harmonic restraint disabled.

2. The relay should trip when harmonic restraint is disabled.

3. If the relay trips, then play back the inrush case again with harmonic restraint enabled.

4. The relay should not trip when harmonic restraint is enabled.

Figure 7: Transformer Inrush Test Procedure Flowchart

ADVANCED TEST— ADJUSTING THE LEVEL OF 2 ND HARMONIC CONTENT

It is possible to reduce the amount of 2nd harmonic content present in the inrush current during the injection test. You can

reduce the level of 2nd harmonic current until the restraint no longer blocks the differential protection. For example, 10% is typically the minimum level acceptable to set the 2nd harmonic restraint; if it were set lower, tripping might be significantly delayed for heavy internal faults due to harmonics generated by CT saturation. The software shown in Figure 8 illustrates this process:

1. Isolate the fundamental component and 2nd harmonic component in B-Phase current (IB).

2. Multiply the 2nd harmonic content by a factor to reduce its magnitude to the pickup level selected for the 2nd harmonic restraint. For this particular case, the minimum pickup is 10%. Therefore, the multiplication factor is 0.7 (i.e., 10% 14% ).

3. Re-assemble the B-Phase current by adding the fundamental and 2nd harmonic back together (depleted Ib in the case of Figure 8).

4. Inject the adjusted current into the relay.

EVEN HARMONIC RESTRAINT DURING TRANSFORMER INRUSH

Events such as transformer energization can be captured by utilities using digital fault recorders or numerical relays and then later played back via COMTRADE to observe relay performance. Some customers have access to software such as the Alternative Transients Program (ATP) and can build their own transformer models to simulate inrush. This is a practical method to check that the relay is properly set. One example of playback is to evaluate the performance of the restrained differential protection for transformer inrush with varying levels of harmonic content in the current waveforms.

Transformer differential protection has historically used the 2nd harmonic content of the differential current to prevent unwanted operation during transformer inrush. It is advantageous to use both the 2nd and 4th harmonic content of the differential current. The relay can internally calculate the total harmonic current per phase as follows:

I2-4 = 2 4 2 2 I I

The sum of the two even harmonics per phase helps to prevent the need to lower the value of restraint, which could cause a delayed operation if an internal fault were to occur during transformer energization.

Cross-phase averaging also helps prevent unwanted operation during transformer inrush. Cross-phase averaging averages the even harmonics of all three phases to provide overall restraint. The cross-phase averaged harmonic restraint can be internally calculated by the relay as follows: Ir2-4 = 2 4 2 2 4 2 2 4 2 C B A I I I

The transformer relay with even harmonic restraint and cross-phase averaging tested for the following cases did not malfunction. The inrush currents presented here were created

Figure 8: Adjusted Inrush Current

using EMTP and have a very slow rate of decay. Figure 9 is a one-line diagram illustrating the 600 MVA auto-transformer.

Figure 9: 600 MVA Auto-Transformer Single-Line Diagram (Delta Winding DAC)

87T RELAY SETTINGS

The auto-transformer differential protection settings are as follows:

FIRST CASE — BALANCED INRUSH

Energized Line with Bank from Single End (No residual flux)

10A: Total Phase Currents for Balanced Inrush

TAP1 = = 4.18 [27]

TAP2 = = 3.77 [28]

87T Pickup = 0.5 per unit

Slope 1 = 25%

Slope 2 = 75%

Break Point = 2.0 per unit

Even Harmonic Restraint = 10% (cross phase averaging enabled)

10B: 2nd Harmonic Component Currents for Balanced Inrush

Figure 10C: 4th Harmonic Component Currents for Balanced Inrush

Figure

Figure

RELAY COLUMN

SECOND

CASE — BALANCED INRUSH

Energized Bank from Winding Two with Winding One Open (No residual flux)

Figure 11A: Total Phase Currents for Balanced Inrush

Figure 11B: 2nd Harmonic Component Currents for Balanced Inrush

Figure 11C: 4th Harmonic Component Currents for Balanced Inrush

THIRD CASE — UNBALANCED INRUSH

Energized Line with Bank from Single End (Severe A-phase residual flux)

Figure 12A: Total Phase Currents for Unbalanced Inrush

Figure 12B: 2nd Harmonic Component Currents for Unbalanced Inrush

Figure 12C: 4th Harmonic Component Currents for Unbalanced Inrush

FOURTH CASE — BALANCED INRUSH

Energized Bank from Winding Two with Winding One Open (Severe A-phase residual flux)

Figure 13A: Total Phase Currents for Unbalanced Inrush

Figure 13B: 2nd Harmonic Component Currents for Unbalanced Inrush

Figure 13C: 4th Harmonic Component Currents for Unbalanced Inrush

TRANSFORMER DIFFERENTIAL CHARACTERISTIC BOUNDARY TEST

A simple procedure can automate testing the phase differential operating characteristic. A common practice for commissioning distance protection is to test along the boundary of the operating characteristic — for example, circles, lenses. or quadrilaterals. This practice can also be applied to transformer differential protection. Consider the simple example of a two-winding transformer with both sets of windings wyeconnected. To keep the example simple, also assume both sets of CTs are wye-connected and have the same CT ratios — that is, both windings are at the same potential. If you connect the current leads from the test set such that the test currents I1 and I2 are flowing through the transformer windings, then the per-phase differential and restraint currents can be expressed as follows:

Id = [1]

I r = [2]

Where

I 1 = Winding 1 per unit current (A, B, or C-phase)

I 2 = Winding 2 per unit current (A, B, or C-phase)

Express equations [1] and [2] using matrices as follows: [3]

Where

I C = M•I T [4]

RELAY COLUMN

[5]

Invert matrix M in equation [3] to determine the two equations for the test currents: [6]

Calculate the test currents based on an operating point on the differential characteristic as follows:

Table 1 lists the four operating points on the characteristic along with the corresponding test currents. All values are in per unit.

Table 1: Test Currents for Transformer Differential Characteristic Boundary

I 1 = [7]

I 2 = [8]

Note: This test simulates through current, so the second test current should actually be represented as follows when injecting current:

Remember that the test currents are connected at 180 degrees out of phase (i.e., through current).

I 2 = [9]

First Example: Consider a transformer differential characteristic for the twowinding transformer described earlier with the following settings:

Pickup = 0.2 per unit

Slope = 28.6%

Figure 14: Phase Current Differential Characteristic for Two-Winding Transformer

Second Example: Now consider a transformer differential characteristic for a two-winding transformer connected delta (DAB) — wye with wye connected CTs on both side. A numerical transformer differential relay internally compensates the CT currents as follows:

Winding 1 (DAB) Winding 2 (Wye)

are the CT currents.

Use the following equations to test the A-Phase differential element at point 2 of the characteristic shown in Figure 14:

IA1 = I1•TAP1 [13]

IA2 = I2•TAP2•√3 [14]

From Table 1:

I1 = 0.8 per unit [15]

I2 = -0.6 per unit [16]

IA1 = 0.8•TAP1 [17]

IA2 = -0.6•TAP2•√3 [18]

IA1 and IA2 are the two test currents.

CONCLUSION

This article demonstrates different techniques to test the multifunction numerical transformer protection relays and shows how to incorporate them using automated test software COMTRADE for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays since it can be used to replay actual operating conditions or simulate very complex events, such as transformer energization when there is remnant flux on the core of a winding.

The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using EMTP. The first case can be used to test harmonic restraint for any transformer

differential protection relay that has phase current inputs rated 5 amps 60 Hz; therefore, it is a universal test. The second case shows that by using the RMS value of both the 2nd and 4th harmonic current, it is possible to have proper restraint for a difficult case of transformer energization where the core has significant remnant flux. Finally, it is shown how to automate testing the boundary of the phase differential operating characteristic to properly test the relay settings; at least four points are tested, which verifies the minimum pickup, break point, and both slopes.

Steve Turner is Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He also was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for doubleended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including: Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of the IEEE and serves in the IEEE PSRC.

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FAILURE MODES

To properly perform transformer maintenance, it is important to identify all, not just some, of the possible failure modes: Electrical, Mechanical, and Dielectric. These can further be broken down into internal tank and external tank. This article highlights the often-overlooked external failure modes rather than the typical internal modes identified in most maintenance programs.

EXTERIOR MAINTENANCE

Exterior maintenance centers on the LTC drive mechanism, cooling fans, pumps, controls, and gauges.

The heart of the LTC drive system is a motor. Some are three-phase, but most are typically single-phase fractional horsepower, and they have many failure modes, which can result in LTC failure. While most of us think we understand motors, do we really?

Motors are rotating and repelling electromagnets that require current to produce the electromagnetic flux that generates the twisting force known as torque and voltage to push that current. They are very proportional; if the voltage drops, the current will climb, and if the voltage climbs, the current drops.

Motors are obedient in the sense that under some circumstances, they will destroy themselves trying to rotate the load by drawing the current they need to generate the torque required to rotate, if not protected by a current limiter such as a fuse or breaker. Their internal impedances are variable.

While they are a virtual short circuit at the moment they are energized, that quickly changes as they approach normal operating speed. The twisting force or torque is dependent on the strength of the magnetic flux formed between the stator or stationary winding as compared to the rotating winding or rotor. The rotor then has a shaft connected to the load extending from the middle of the rotor. The flux requirement and the current required to produce it are determined by the load on the shaft.

Although polyphase motors do not require any help to rotate, single-phase motors (Figure 1) can require three additional parts to begin rotation: (1) the start winding, (2) a centrifugal switch, as in Figure 2, used to disconnect the start winding when the motor reaches approximately 85% of rated speed, and (3) a starting capacitor, as shown in Figure 3. When a motor is first energized, the current drawn is equivalent to the stalled current and is large enough to quickly overheat the winding. This heat, if it persists, will destroy the winding insulation and eventually the motor. The current reduces rapidly as the motor picks up speed and develops a counter EMF to oppose the source; ac induction motors behave as transformers with a shorted secondary until the rotor begins to move.

Figure 1: Single-Phase Motor

Figure 2: Centrifugal Switch

Figure 3: Starting Capacitor

COMMON MOTOR PROBLEMS (LTC FANS AND PUMPS)

The most common motor problems are related to improperly applied voltage and current. As connections get old and loosen due to thermal cycling, corrosion, and poor crimping, their resistance increases and results in voltage drop. It is easy to determine if this occurs by measuring the voltage before startup and while running at full speed using a good voltmeter. If the voltage drops by more than 10%, one of the previously mentioned conditions exists. Slow start-up can be caused by excessive load or bad start capacitors (Figures 4 and 5). The capacitance of the latter can be measured with any number of good capacitance measurement meters. If the capacitance has changed more than 5% from the tolerance printed on the can, or 10% from the rated value, it should be changed. Because ac capacitors are not polarity sensitive like dc capacitors, the two types cannot be interchanged. If the capacitor is satisfactory, mechanical issues are the next areas to investigate.

Bearing wear, improper lubrication, or rust in jack shafts, sprockets, gears chains, and levers all increase the torque requirements and the measured current (Figures 6 and 7).

Any mechanical or electrical problem that slows the operation of the LTC causes extended transition times, and ultimately, failure in the selector, transfer, and reversing switch contacts. While it might be assumed that the failure is due to bad contacts, the original problem could actually be in the drive motor and mechanism.

Other LTC failure modes are directly attributed to poor maintenance in the controls of the LTC. The contacts must not only move in a timely fashion, but also must stop with precision directly on their stationary mates. The moveable contact can’t stop short, nor can it coast past the proper position. Therefore, one of the following must be employed:

Figure 4: Capacitor Located Under the Cover

Figure 6: Rusty Chains Due to Leaking Explosion Diaphragm and Lid Gaskets

Figure 5: Externally Mounted Start-Up Caps

Figure 7: Frozen Universal Joint Due to Aged and Broken Rubber Joint Cover

• Mechanical braking using drums or bands

• Dynamic braking where the motor is short circuited momentarily

• Plugging where the motor is electrically reversed to stop its forward motion

All are required to occur exactly on step, in time, every time. The cam and position switches, which control these functions, need maintenance and lubrication on a regular basis as well. Lastly, the LTC must recognize when it has reached the last

Figure 8: End of stroke stops are mechanical stops to prevent the LTC contacts from moving past the last step.

End of stroke limit switches are used to electrically disengage the motor drive when step 16 is reached.

Threaded bar step positioner requires regular lubrication.

step and protect the motor from trying to rotate past the mechanical stops. Step 17 on a 16-step changer is not good (Figure 8)!

Mechanical brakes require adjustment to ensure the brake releases when the operating solenoid is engaged to let the motor rotate but must re-engage exactly at the correct spot required to position the contacts. Brake bands wear over time and need adjustment or replacement (Figure 9).

Figure 9: Brake release solenoid is electrically energized to release the brake, but when de-energized, uses a spring to reapply the brake. Timing is critical.

Brake bands use friction to stop the LTC motor in the correct position and must be adjusted periodically.

In closing this section on LTC mechanisms, a failure example is illustrated in Figure 10. Although the failure is located in the LTC tank, the cause is lack of maintenance in the control section, possibly due to binding, low torque, low voltage, high current, bad starting capacitor, etc. Good maintenance procedures should include servicing these parts on a regular basis, which can prevent failures in the LTC tank.

ELECTRICAL CONTROLS

Electrical maintenance is normally only thought of as the in-depth testing of the core and coils, such as power factor, TTR, excitation, winding, and resistance, etc. Seldom are the external controls for the pumps and fans tested to see if they function properly, much less checking calibration for accuracy.

It is widely accepted that a continuous increase of 8°C to 10°C above rated temperature can reduce operating life by 50%. Therefore, it is very important that the cooling system on a transformer works as designed to turn on the fans and pumps before the oil temperature reaches the rated upper limit.

Top oil and hot spot gauges need calibration using a calibrating oven to see if the needle tracks the actual oil temperature or drifts as the temperature increases (Figure 11). It’s not uncommon for the error in reading to change as the temperature increases. Adding or subtracting a fixed amount to

the actual reading compensates for a linear change. A non-linear change requires a replacement of the temperature gauge. Additionally, determine if the switch set points close at the desired temperature and can be adjusted up or down to compensate for gauge errors. The final check is to see if the electrical switch actually changes state when the set points are reached (Figure 12).

In a situation where the fans turn on late by 10 degrees, the windings can be continually subjected to temperatures past their design limit, thereby reducing insulation life. If the transformer is set to trip on high temperature, a bad gauge can trip the unit for no actual reason below the desired temperature, causing collateral damages or an unplanned outage.

Figure 10: Damaged Moveable Contact Due to Malfunctioning Brake Circuit in the Motor Control

Figure 11: Transformer Temperature Gauge with Electrical Set Points to Bring Pumps and Fans On- Line

Figure 12: Capillary Tube Temperature Well Calibration Oven

MECHANICAL PROBLEMS

Pump problems have negative consequences as well. If a pump starts at a higher temperature than planned, it may be difficult to return the transformer to the desired temperature during hot weather or when the load is above normal. A pump that fails to start leads to insulation degradation. If a pump fails completely, the transformer may fail in a very short period of time. Most transformers have an operational capability less than the OA rating with no pumps running and can overheat with minimum load. Pump failures can be mechanical as well as electrical. Pump motors use a spacer called a thrust washer to center the impeller in the cast iron housing to prevent drag. As a pump ages, the thrust washer wears and eventually permits the impeller to drag on the housing, depositing large amounts of brass and cast iron in the transformer. These filings will be distributed everywhere, including the windings, eventually causing winding failure (Figure 13).

Using an ultrasonic detection device (Figure 14) can quickly identify a number of failure modes, such as gas leaks, partial discharge, vacuum leaks, and mechanical wear (Figure 15), by converting vibration into audible sound the inspector can hear and record in his head set.

Fan failure is common in a majority of companies. In the case of forever-sealed bearings, little maintenance is required other than keeping them clean and unobstructed. Fans are designed for free, unrestricted airflow that loads the motor to a specific torque and current draw. When the fan bearings become dry or the blades obstructed, the current rises to compensate for the increased torque requirements, resulting in overheating and shortened motor life. Simple maintenance such as adding grease to bearings, removing debris from the blade guards, and checking the start capacitor all add many years to the life of the fan and transformer (Figures 16 and 17).

Figure 13: Thrust Washer Failure Modes

Figure 15: Use of Ultrasonic Detector to Determine Bearing Wear in Pumps and Fans

Figure 16: Bird nests play a primary role in fan failure and overheating of transformers.

Figure 14: Visual Representations of Bearing Wear Using Ultrasonics

DIELECTRIC QUALITY

The final category of overlooked items involves rigorous and regular oil quality testing. Oil testing falls into two basic categories: dissolved gas analysis (DGA) and oil quality testing (OQ). DGA is used to look for health issues, ranging from basic overheating to partial discharge and internal arcing. By understanding the differences in how gas is generated, it can be determined if the internal problem is serious or can be controlled by load. The results can also point to what electrical tests to perform if the problem proves to be more than operating issues.

Considering many problems are slow to evolve, taking OQ samples yearly provides adequate protection. But in the case of problems typically caught by DGA, take oil samples from the main tank and LTCs more often. It is recommended to pull DGA samples twice a year due to the speed at which an LTC or winding problem can progress. The cost per sample is marginal compared to a transformer or even just an LTC failure and can be cost justified with one LTC save.

CONCLUSION

As explained, what constitutes correct transformer maintenance is not always clear. To provide 100% equipment protection, it is important that technicians and maintenance engineers are aware of all failure modes on each specific equipment type. Suitable tests and service procedures, and the appropriate intervals between them, can then be developed. Once a comprehensive plan is devised to address all three failure modes — electrical, mechanical, and dielectric — the next important step is to implement it.

Typically, OQ screens are ordered in groups of five, seven, or eight separate tests that include dielectric strength, moisture, interfacial tension, acidity, power factor, and color. Other more stringent tests include furanic compounds to determine the remaining life of the insulation, and power factor at 100˚C to look for polar contaminants closer to the true operating temperature of the equipment under test.

Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

Figure 17: Fan failures due to debris also contribute to transformer overheating.

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WORKING SAFELY WITH POWER TRANSFORMERS IN THE UTILITY SECTOR

BY RAY CURRY, American Transmission Company

Here’s a reflection on power transformers/accessory equipment, installation work methods, rigging/moving, and safety practices from the 1970s to today.

When examining America’s electrical grid, power transformers are a key component. They are required for generator step-up (GSU), transmission, and distribution duty. In many locations, the Internet Age has caused a large increase in power demand. The bulk of the grid load is handled by aging power transformers, most of which were built in the 1970s and 1980s, with a few even older. These transformers were expected to have a 30- to 35-year life, but many are beyond 45 years.

While many utilities are adding new transformers, the planning, purchase, and installation time is very long. Planning can be as long as five to seven years with the actual purchase taking 12 to 18 months. Installation for most transformers will take as long as three weeks.

The fact is that everything is speeding up with no end in sight, and many changes and improvements concern power transformers as well. To list a few:

• Better designs for longer life cycle

• OEM components manufactured with ISO 9000 standards

• Better nondestructive testing

• Insulation materials suited for higher voltages and thermal stresses

• Improved installation and oil processing/handling

• Enhanced shipping and GPS tracking

Workforce skills and equipment are also improving. The major part of any transformer installation involves moving a large, heavy piece of equipment that can be badly damaged by rough handling. To meet today’s utility specifications, many rigging and heavy hauling companies have invested in the best equipment as well as a skilled, trained workforce versed in an established safety program with a proven track record.

Many of the larger transformers that need to be shipped a great distance (250MVA up to 800MVA) must be shipped by rail. With very few substations having a rail siding, a transfer vehicle is required to move the transformer from the rail siding to the transformer pad within the electrical substation. From the 1970s to now, these drayage vehicles have been re-engineered to be more versatile with hydraulic systems to raise, lower, or level the working platform.

Each vehicle has 16 axles that can be steered independently of one another. Self-propelled vehicles are a great advantage over older equipment, which required a tractor. In many older substations, space surrounding a large transformer can be very restrictive.

The transport and installation of power transformers continues to become safer and more efficient.

Newer cranes are equipped with digital readers, giving the operator real-time, out-of-limits alarms for different parts of the crane, such as boom loading and outrigger position.

For many years, utilities have been associated with having strong safety programs. Today, more and more utilities are following OSHA regulations and require all contractors to have a positive safety program of doing the same. Qualified Crane Operators are now the norm. The use of fireresistant clothing is now required by most utilities, along with consistent use of PPE. In the 1970s and 1980s, this would not have been the case with many rigging and hauling contractors.

Today, the movement of the transformer, whether by rail or truck, is tracked using a realtime GPS device. The most popular device is a Lat-Lon, which uses a self-contained battery pack. This device records all movement in the X, Y, and Z axis with adjustable alarm levels. An important added feature with this device is its ability to record the main transformer tank pressure. Most transformers are shipped with two to three pounds of certified dry air in the main tank. The premature loss of this air pressure will cause, in most cases, additional vacuum/oil process time.

From the 1960s through the 1980s, a mechanical clock recorded all impacts to the transformer during shipping. This impact recorder used paper on a roll to make the recordings. When the shipped load reached a destination, the paper roll was analyzed for any impacts. Compared to where the technology is now with real-time GPS, the old instrumentation was very unreliable and often failed to provide accurate data. The only backup to this was to check the core ground of

the transformer and compare to the factory test measurement before shipping. Today, there is an additional test called Sweep Frequency Response Analysis (SFRA), which will be covered in the next article in this series.

A valuable aid for today’s commissioning engineer planning a large transformer move is the ability to hire a logistics management firm. Now, contractors will arrange all the services and order a special rail car. The agent will also take care of interaction with railroad agents, schedule a heavy hauling company, and file all state and local permits to accomplish a safe and coordinated move. Along with the permits, an over-the-highway move may require a state patrol inspection of the load and on-road escort, all of which is taken care of by the logistics company.

Now that the transformer is in the substation and on the pad, the next article in this series will cover assembly, vacuum/oil processing, testing, and placing the transformer in service. This article will also address Maintenance Zero Steps and the use of Behavior Based Safety Observation (BBSO).

Ray Curry graduated from Penn State University in 1969. After a short time in the U.S. Navy, he began working at Westinghouse Electric in the East Pittsburgh Division and the PCB Division at Trafford, Pennsylvania, in 1971. In 1977, Ray relocated with Westinghouse to St. Louis, Missouri, working in the E&ISD Division as a Field Service Engineer specializing in high-voltage switchgear and power circuit breakers. In 1981, he received extensive factory training for the installation and startup of large power transformers. He was a PCB Contracts and Negotiations Specialist in the Transform Program from 19871994. In 1995, Ray completed a Bachelor of Arts in Management of Technical Services from Ottawa University, followed by a master’s in 1997. Ray managed electrical utilities in two Municipal Electrical Systems for the cities of Chanute and Garden City, Kansas, from 1994 to 2000. In 2001, he worked as a Field Service Tech for Robicon, installing and maintaining HV electrical drives and motor control systems. From 2007 to present, Ray has been a Commissioning Engineer with American Transmission Company, building and maintaining over 500 69kV -138kV to 345kV electrical substations. He sits on ATC’s Safety Committee and has maintained an active affiliation with NETA for six years.

IEEE STANDARD C57.152-2013

IEEE is the world’s largest professional association dedicated to advancing technological innovation and excellence for the benefit of humanity. The IEEE transformer committee handles all matters related to the application, design, construction, testing, and operation of transformers, reactors, and other similar equipment.

The IEEE Transformer Committee met in Dallas in 2007 to revise the existing guide for routine testing in the field, IEEE 62, Guide for Diagnostic Field Testing of Electric Power Apparatus - Oil Filled Power Transformers, Regulators, and Reactors (R2005). At the time, a vast number of old and new testing methodologies and practices were used in the field but not covered by the IEEE 62 standard. It was logical to create a new or revised guide under the C57 standard series. The C57 standards already contained other transformer-related guidelines administered and supervised by the IEEE Transformer Committee (Figure 1).

The new guide for diagnostic field testing of fluid-filled power transformers, regulators, and reactors was balloted and approved by RevComm in 2013. The work was led by Jane Verner (Chair), Loren Wagenaar (Vice Chair), Kipp Yule (Secretary), and supported by many members of IEEE who dedicated long hours in revisions and contributions to the new guide.

The comparison between IEEE 62 and IEEE C57.152 brings something else to this discussion. The new Diagnostic Test Chart complements the old one, keeping the existing practices and adding those methods not considered previously. A comparative analysis shows the following methodologies were added to the new guide:

Windings:

• Frequency Response Analysis (FRA)

Insulating liquid:

• Furan Analysis

• Corrosive Sulfur

Current transformers:

• Ratio

• Polarity

• Resistance

IEEE C57.152 (Chapter 5) also considered the importance of providing a maintenance chart where the end user could select the testing practices recommended (REC), as-needed (AN), and optional (OPT) for different stages during the service life of the transformer: commissioning, inservice, after protection trip due to system fault, or after protection trip due to internal fault. In this chart, induced voltage and dielectric frequency response (DFR) are listed as optional techniques.

Not only are more testing methodologies listed in the new maintenance and diagnostics charts, but also included are new annexes

Figure 1: IEEE C57 Series Dedicated to Transformer Guidelines and Standards

developed to complement the guide regarding these new additions:

• Annex D (informative) Dew Point Test

• Annex E (informative) Furan Testing

• Annex F (informative) Frequency Response Analysis

• Annex G (informative) Dielectric Frequency Response

• Annex H (informative) Other methods to verify polarity from previous field test guide revisions

• Annex I (informative) Particle Count

• Annex J (informative) Bibliography

Only general information about FRA and DFR was included in annexes F and G because when C57.152 was close to being published, other working groups were developing specific guidelines for the advanced diagnostic techniques of SFRA and DFR. Frequency response techniques have been used in the field for over 20 years. Researchers worldwide have found SFRA and DFR useful not only in transformer diagnostics, but also in other electrical apparatuses in the field.

For now, focus is on transformers where the electro-mechanical and dielectric condition can be evaluated and traced for better diagnostics and interpretation of results. In 2012, a new working group was created within the IEEE Transformer Committee to develop a guide for DFR analysis, PC57.161, which is currently under development.

CIGRE

Founded in 1921, the Council on Large Electric Systems (CIGRE) is an international nonprofit association that joins forces with experts all over the world to improve electric power systems of today and tomorrow. Of course, the transformer topic is covered by several technical brochures dedicated to particular areas of interest in the scientific and operational fields.

CIGRE 445, the guide for transformer maintenance, provides a diagnostics matrix where a line is drawn to differentiate basic electrical testing from advanced electrical testing (Figure 2). In this publication, frequency response techniques in time and frequency domains are grouped together with

partial discharge (PD) testing as advanced electrical diagnostic techniques.

Figure 2: CIGRE 445 - Electrical Tests and DGA Diagnostics Matrix

CIGRE pioneered publishing guidelines dedicated to the frequency response methods. In 2008, CIGRE published Technical Brochure 342 — Mechanical Condition Assessment of Transformer Windings Using Frequency Response Analysis (FRA). This document is an excellent reference describing the principles of FRA, the suggested best practices for making repeatable measurements, and guidance for interpretation.

CIGRE also undertook a large project to investigate the frequency response of the dielectric components inside the transformer, publishing Technical Brochure 414 — Dielectric Response Diagnoses for Transformer Windings in 2010. As before, CIGRE provided a well-developed document, describing the transformer dielectric response model, the best testing practices, and guidelines for the interpretation of results.

IEC

Founded in 1906, the International Electrotechnical Commission (IEC) is the world’s leading organization for the preparation and publication of international standards for all electrical, electronic, and related technologies.

Prepared by Technical Committee 14, the IEC 60046 standards series covers technical areas related to transformers. Standard IEC 60046-1 (2011) is the latest revision available for power transformers and IEC 60046-18 Ed. 1 (2012) addresses the methodology, best practices, and minimum requirements for measuring equipment as well as suggestions on formatting the data resulting from the test.

IEC 60046-18 also includes several annexes. Annex A covers the measurement lead connections. This is sometimes critical, especially when the operator is not applying an adjustable ground braid to the transformer bushing. On subsequent attempts to generate the transformer signature, replicating the high-frequency band is almost impossible. The shortest distance between the bushing terminal and the bushing’s bottom flange is recommended and addressed by CIGRE in Technical Brochure 342.

Annex B covers factors influencing FRA measurements including residual magnetization, use of different liquids and the level of liquid filled in the tank, temperature, and others. It also includes a few examples of confirmed damages in the windings detected by the FRA test. Annex C covers the applications of FRA, and Annex D provides examples of measurement configurations.

TRANSFORMER ADVANCED DIAGNOSTICS BY FREQUENCY RESPONSE TECHNIQUES

The objectives and scope of each frequency response method must be clearly understood before it can be chosen for the most appropriate application.

Frequency response analysis or sweep frequency response analysis (SFRA) is a comparative test to evaluate the electro-mechanical condition of the transformer. Deviations between frequency responses indicate mechanical and/or electrical changes in the active part of a transformer.

Dielectric frequency response or frequency domain spectroscopy (FDS) is a test to evaluate the overall condition of the transformer’s insulation. This overall insulation evaluation allows the user to identify:

• The percentage of moisture concentration in the solid insulation

• The conductivity or the dissipation factor of the liquid insulation corrected to 25°C

• The thermal behavior of dielectric parameters at specific frequencies, determining an accurate power factor / dissipation factor correction not based on table correction factors but on the individual dielectric response of the unit under test (UUT)

• The presence of contaminants creating a distortion of the dielectric response (also called non-typical dielectric response)

A deeper look at each technique is helpful to understand their advantages.

Sweep Frequency Response Analysis

According to control theory, the behavior of a linear single-input/single-output (SISO) system can be described with an impulse response h(t) or its transfer function H(j ) (Figure 3).

Figure 3: SISO — Representation of a Transfer Function in Time and Frequency Domains

In the case of power transformers, the electromagnetic phenomena is well described by different laws (Faraday, Lenz, Ampere); by simple inspection, it is easy to understand that the physical structure of the winding can be represented in the electric language by an RLC complex circuit with multiple series and parallel combinations of these components (Figure 4).

Figure 4: Simplified Diagram of the Winding Configuration

on the other electrode. The test is carried out at low voltage (200Vp) for transformer testing. For environments with high interference, a voltage amplifier increases the signal-to-noise ratio. The use of a voltage amplifier is fundamental for the analysis of bushings and instrument transformers.

A two-winding transformer can analyze the following:

• CHL — capacitance between HV and LV windings (i.e. inter-winding capacitance)

• CHG — capacitance between HV winding and ground

• CLG — capacitance between LV and ground

• Bushing C1 and C2 capacitances, but only if test tap is available in the bushing

• Only oil sample DFR

pS/m, T=20°C)

For interpretation of DFR results, the XY model explains the relationship between the solid insulation, the liquid insulation, and the system geometry. The XY model is well described in CIGRE 414 and briefly described below in Figure 9.

The response is a combination of a two-material complex dielectric system. For the majority of power transformers, the complex insulation is composed of liquid insulation (mineral oil) and solid insulation (cellulose). The dielectric response of these two materials provides an indepth understanding of the insulation system and allows differentiation between the condition of the liquid insulation versus the condition of the solid insulation.

An example of a transformer in excellent condition is presented in Figure 8. Moisture in the solid insulation is only 1% and the conductivity of the oil is 1x10-13. Temperature of the insulation system in this example is 20°C.

Following the XY model and using mathematics to match the readings to those in a well-developed database, users can determine the moisture concentration in the solid insulation and the conductivity ( ) of the liquid insulation. The information indicates the overall condition of the insulation and is a simple but powerful tool for coordinating and prioritizing necessary actions to be taken on a transformer.

Note that DFR is not an invention of the last millennium; it was developed in the mid 1990s and continues to evolve. Because it has a proven effectiveness in the field, its applications grow every day. No doubt, part of this development is the use of a multi-frequency measurement system capable

Figure 7: Hook-Up Diagram for DFR Testing on a Two-Winding Transformer

Figure 9: The Physical (a) and the Modeling (b) Representation of the Inter-Winding Insulation

Figure 8: DFR of a Transformer’s Liquid-Paper Insulation (X=20, Y=20, %mc=1%, =1E-13

ENSURING ACCESS TO

The Right Equipment at the Right Time –and at the Lowest Cost

BY HERB OSTENBERG, Electro Rent Corporation

Creating a cost-effective plan that ensures the availability of the right test equipment at the right time requires bottom-up planning between two groups: test and finance.

Traditionally, capital purchases of test equipment are timed to meet expected demand for test capacity. However, because actual demand is rarely linear, in-hand capital equipment may be underutilized at times and insufficient at others. An acquisition plan that optimizes the mix of owned (e.g., new or used) and rented equipment will ensure flexibility in test capacity and financial management.

This concept can be implemented using a practical decision framework that benefits both groups. Test teams will achieve revenue objectives through increased productivity. Similarly, the finance team can address its need for upfront planning and ongoing monitoring relative to capital and operating budgets.

RECOGNIZING THE REALITIES

The classic model of a new-product forecast is linear: introduction, growth, maturity, and decline. Purchases of capital equipment are based on the forecast, and the goal is to have the right amount of equipment at the right time (Figure 1).

Figure 1: Traditionally, expected demand has driven capital equipment purchases.

However, actual equipment demand is nonlinear due to factors such as customer buying cycles, design delays, unexpected new projects, parts shortages, and economic downturns. Whatever the cause, the test function is often faced with having either too much or too little equipment (Figure 2).

Figure 2: A plan that can’t respond to variations in demand may incur costs or cause lost revenues.

Having too much capital equipment has a negative effect on costs, and consequently, on margins. Having too little is also undesirable because it can delay time-to-market at the intro stage and affect delivery times and even revenues during the growth stage.

TRACKING DEMAND WITH A HYBRID APPROACH

An acquisition plan that optimizes the mix of purchases — new or used equipment — and test-equipment rentals will ensure flexible capacity. This variable-cost rental model is a useful alternative to the fixed-cost purchase model (Figure 3).

A D VANCEMENTSINTEC H

Figure 3: Because the variable-cost rental model tracks actual demand, it can reduce costs and enhance revenue.

A hybrid plan is often the optimum way to ensure timely access to the right equipment.

This approach uses funds from capital expenditures (CAPEX) and operating expenses (OPEX) to acquire individual pieces of test equipment.

An important key to success is a collaborative, bottom-up approach to planning that includes the test and finance teams. From a test perspective, having the right equipment at the right time provides flexibility in three ways:

1. Higher-performance test equipment is available to support new technology requirements.

2. New-generation instrumentation often saves time through simplified setup and faster measurement speeds.

3. Older-generation equipment can be repurposed to support legacy applications.

The net benefit: The organization is in a better position to achieve revenue objectives through increased test productivity.

ESTABLISHING A STRUCTURE FOR ADAPTABILITY

A five-part framework can be used to develop the procurement plan and optimize the spending mix: accounting requirements, planning considerations, decision flow, acquisition alternatives, and procurement analysis.

Part 1: Accounting requirements. Test equipment can be funded using CAPEX, OPEX, or a combination. CAPEX funds acquire assets such as test equipment that is intended to be owned. OPEX funds are used to pay for business operations, including the use of test equipment.

Before deciding, it is necessary to understand the accounting requirements and implications for each alternative (Table 1). There are six essential items to consider: depreciation costs, book value, fair-market value, asset tracking, sales tax, and property tax. The table provides a side-by-side summary of the relevant requirements and implications.

ADVANCEMENTS IN TECHNOLOGY

Table 1: Important Implications of Accounting Requirements for CAPEX and OPEX

Part 2: Planning considerations. After the accounting requirements are understood, six factors affect the planning stage. Two of these are financial: availability of capital to fund needed test equipment and flexibility to pass along variable overhead costs to customers.

Four are technical or temporal. First is confidence that each piece of test equipment is the best choice for the specific application requirements. Next is the length of time an instrument is expected to be needed for current or expected projects. Third is the known or expected availability of next-generation

equipment that will provide significant improvements in test productivity compared to in-place test equipment. Last is the expected utilization rate for each instrument over the timeframe it will be in use.

These financial, technical, and temporal elements carry over to the decision map.

Part 3: Decision map. The six planning considerations fit into the framework illustrated in Figure 4. Three are simple yes/ no decisions, and the other three are plannedusage decisions.

Figure 4: This decision map helps identify the best funding choice for each piece of test equipment.

Individually and collectively, these decisions form a variety of paths that lead to one of two recommended decisions for each piece of equipment: buy using CAPEX or rent using OPEX. As shown, six outcomes lead to the use of OPEX. If every answer is “yes,” then CAPEX acquisition is recommended.

Part 4: Acquisition alternatives. There are three funding methods:

• CAPEX: plan to own the equipment

• OPEX: plan to use the equipment

• Combination: plan to use and eventually own the equipment

ADVANCEMENTS IN TECHNOLOGY

OPEX is used to rent equipment or take on an operating lease. In many cases, rental equipment has immediate delivery, and the minimum term typically ranges from several days to one month. An operating lease can be for a new or used instrument and typically has a minimum term of 12 months.

In the combination approach, the alternatives are to rent with the option to own or rent to own from the start. With option-to-own, a percentage of the rental expense is applied to the purchase. With rent-to-own, 100% of the rental expense is applied to the purchase.

Each of these has two or three alternatives. With CAPEX, the choices are to buy new, buy used, or take on a finance lease. Finance leasing means buying new or used equipment with payments spread over time.

To compare these alternatives, five criteria are especially useful: minimum term, ability to upgrade to next-generation equipment, ability to swap out a failed instrument, inclusion of repair, and inclusion of calibration. Table 2 provides side-by-side summaries and comparisons.

Table 2: Side-by-side Comparison of Rental Alternatives (blue indicates CAPEX, orange is OPEX, and green is a mix)

ADVANCEMENTS IN TECHNOLOGY

Another element worth considering is the pluses and minuses of working with equipment manufacturers or equipment-leasing companies. Suggested selection criteria include the range of acquisition alternatives and the ease of doing business with the company. Naturally, breadth of catalog and the possibility of one-stop-shopping is another important factor.

Part 5: Procurement analysis. Projected expenses provide a common yardstick for buy-versus-rent decisions. The key drivers are the same plannedusage variables that appear in the decision map: length of time the equipment will be needed, availability of next-generation equipment, and planned utilization. Secondary drivers are maintenance costs and the cost of rentals as a percentage of buying.

Figure 5: Comparing the expected costs for each of the three instruments reveals the lower-cost approach.

As an example, these concepts can be used to optimize the mix for a set of instruments needed for a specific project. Instruments A, B, and C each have expected costs to buy/maintain or rent/maintain (Figure 5). Possible totals for the overall project cost include buy all three ($520,000), rent all three ($445,000), or create an optimized mix ($330,000). In this case, the mixed approach provides the lowest cost: rent A, buy B, and buy or rent C (whichever meets current budgetary constraints).

MOVING FORWARD

Through upfront collaboration, test and finance groups can meet their respective objectives. The hybrid approach described here optimizes the mix of buying new or used and renting. This is often the most cost-effective way to ensure the availability of the right test equipment at the right time.

Another important consideration is the choice of provider, which may be an instrument manufacturer or an equipment-leasing company. Key selection criteria include breadth of catalog, the range of available acquisition alternatives, and the ability to deliver added value. For example, some rental companies can provide planning tools that help assess the true costs of the alternatives. In many cases, these are based on decades of experience managing a huge array of test assets worth millions of dollars.

Herb Ostenberg has spent his entire career in the Test and Measurement business. After graduating from Montana State University with a BSEE, he joined Hewlett Packard. Ostenberg moved between a number of roles at HP before becoming the Area General Manager for sales, marketing, and support for the Rocky Mountain and Pacific Northwest states. While at HP, Ostenberg led a global reengineering effort to integrate HP’s outside sales, call centers, and the web into a more cohesive customer-centric organization. Ostenberg joined the HP T&M spin off, Agilent Technologies, and again had several different roles including Vice President and General Manager of the Americas Sales Region. He joined Electro Rent Corporation in 2009 and is the Senior Vice President for North American Sales.

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COMBINED CURRENT AND VOLTAGECONTROLLED SOURCE IN ARCING CONTACTS CONDITION ASSESSMENT

BY ADNAN SECIC AND RADENKO OSTOJIC, DV Power, Sweden

Preventive maintenance of a high-voltage circuit breaker (HVCB) begins with collecting a useful data set, directly where the breaker is installed. Manufacturers provide limits for the majority of testing parameters. Those limits are very useful for maintenance companies as a reference for preventive maintenance diagnostic procedures.

For example, consider the opening time, which is a standardized parameter available on the breaker nameplate or in its technical documentation. The manufacturer guarantees that after leaving the production line, the certain circuit breaker (CB) type will trip within these limits after receiving a command from the relay protection. In the event of a short-circuit current, a quick response from an HVCB means that disaster in the electric power system can be prevented.

Considering the large number of installed units, data comparison should be as simple as possible. To clarify information in the maintenance history, standardized measurement methods are needed. Today, a large number of international and national standards are defining the way tests are performed and what data is collected during the testing procedures.

DYNAMIC RESISTANCE MEASUREMENT

In addition to reference data, maintenance companies often reuse data collected throughout the previous tests. Although it is the simplest way to compare several numerical results to see whether those results are within expected limits, often a set of collected data is more complex and requires a different representation (e.g. in a graphic form, tabular form, etc.) as well as the use of different comparison methods.

Frequently, an established practice needs the application of new test methods before it becomes a standard. One of these tests is the dynamic resistance measurement (DRM). The output data set of this test includes a graph showing the movement of the breaker contacts measured by a motion transducer, and a graph representing changes in its resistance during operation. It is important to emphasize that this test can be performed on a fully assembled interrupting chamber.

(See photo of HVCB Arcing Contact.)

Standards already indicate the dc current value needed to measure the static resistance of an HVCB (higher than 50A). Logically, the DRM should be performed with the same current values.

CURVE DURING THE CLOSING OPERATION

Why is DRM needed to capture the dynamic resistance curve during the closing operation of an HVCB? Reasons include:

• During closing operation, the arcing contacts will close first. Contact closing is always followed by more bouncing periods than during the contact opening stage.

To simplify comparison of the data, it is necessary to have similar test conditions for different testing intervals. Older measurement methods were based primarily on using a high-power current source and recording the tripping operation data of an HVCB. In this case, considering that the initial state of the breaker is the closed position, it is possible to use the current source to achieve the desired current value.

Note that the DRM test’s main goal is to indicate the state of arcing contacts, not to simulate a real-life situation. Actually, portable testing equipment provides significantly lower currents compared to those that occur in real CB operational situations.

DYNAMIC RESISTANCE

• Arcing contacts conduct the current from the initiation of the current flow at prestrike, followed by pre-arcs stages until the moment the main contacts touch.

• Deformation and erosion of the arcing contact that occurs as a result of electrical and thermal stress generated by the arc is unique to each current-breaking process. For diagnostic purposes, this is why the dynamic resistance curve should be recorded and observed while contacts are moving in both directions.

• It is always better to extend the useful data set to increase diagnostic’s reliability.

These reasons explain why this test is becoming more popular for diagnostic purposes.

Testing methodology

As previously stated, it is helpful to achieve approximately the same test conditions to simplify comparisons of test results. Portable equipment used for DRM needs an integrated power source to provide a high current for the tests.

Tests are performed from the ground, which requires cables attached at the height of the CB bushings. This sometimes requires long cables, but the method is best with a small electric resistance, which in turn, requires a larger cross-section. Obviously, it is easier to carry the equipment if it weighs less, but conflicting requirements make this a challenge.

Therefore, a compromise is needed. The selected source must be very powerful and lightweight, and the only way to accomplish this is to use a high-frequency dc/dc converter, which

High-Voltage Circuit Breaker Arcing Contact

Figure 1: Combined current and voltage feedback on a high-power source provides synergy in testing high-voltage circuit breaker arcing contacts.

will allow higher test currents and eliminate the need for heavy and robust parts such as transformers.

Maximum current from the source will flow when the output load is minimal or when the breaker is in a closed position. Therefore, the logical first step in the DRM testing procedure is a current regulation through the closed breaker contact. Current source can be used for that purpose. In this case, regulator feedback will be the total current measured on a resistor shunt or by any other current measurement method (Figure 1).

After the desired current is achieved, the regulator switches to the voltage control mode, and the feedback value is memorized. The device output can be temporarily disabled, and the breaker set to the open position. This completes the condition setup for performing DRM and achieves the following objectives:

1. Maximum output current is defined by the minimum load (the breaker in a closed position) and is adjusted in the first step of the measurement procedure.

2. Current regulation eliminates influence of the cable’s cross-section and length,

which ensures similar test conditions in different situations.

3. Note that the first reported DRM measurements in the 1990s were performed by using 12V car batteries. Many users are accustomed to this approach.

Starting with the CB open position, the test steps include:

1. Set the output voltage according to the feedback value recorded by the microcontroller unit. The source now works in a voltage mode.

2. Issue the closing command to the closing coil of the HVCB. During the breaker operation, the total current and voltage drop measurements across breaker contacts and motion of the breaker contacts are performed simultaneously

3. After the measurements have been completed, the controller turns off the voltage source.

Safety methodology

A very important aspect of the testing procedure is safety of the test personnel. Grounding the test object on both sides (grounding of the CB terminals) significantly minimizes the risks.

In this case, grounding the CB terminals affects

INDUSTRY TOPICS

the measured resistance. Experimental results are showing that ground resistance and resistance of the grounding cables (Rg) varies in the range of several tens of milliohms (mΩ). On the other hand, resistance of the main contacts (Rm) is much lower and is usually measured in tens to several hundreds of micro ohms (uΩ); the resistance of the arcing contacts (Ra) is usually around a couple of milliohms (mΩ).

This means that due to the grounding of the breaker terminals, the total measured resistance of the contacts will be lower than the actual contact resistance. Total resistance measured for the main contacts is equal to Rmg=Rm || Rg, while the total measured resistance of the arcing contacts is equal to Rag=Ra || Rg.

However, if a high current is applied during the dynamic resistance measurement process, it is still possible to detect the moment of separation of the main and arcing contacts, which is the primary reason for performing the test. This has been confirmed by performing tests on CBs with a high current measurement module.

REAL OBJECT TESTING

Figures 2A and 2B show the DRM results obtained during closing and opening operations of an HVCB. In this figure, results are given in

graphical form to represent coil current, voltage, and current through the breaker contacts, motion of the contact mechanism measured by linear motion transducer, and contacts velocity calculated from motion results. The breaker was grounded on both sides. Measured grounding resistance was approximately 10mΩ, contact resistance approximately 150uΩ, and maximum test current was 100A. This current was regulated with breaker contacts in the closed position, and the regulator was switched to voltage-control mode to provide the necessary conditions for performing the test.

Results show that the average breaker speed during closing of the contacts is slower than the speed during the opening operation. This makes perfect sense because the CB’s main task is to interrupt short-circuit current, implying that the contacts must have a higher speed when opening.

This also implies that the arcing contact overlapping time will be longer for the closing operation of an HVCB. The measured arcing contact overlapping time for the closing operation was 3.8ms, and for the opening operation it was 2.3ms.

During the closing operation, DRM provides more insight into resistance changes inside

Figure 2A and 2B: DRM Results – Top graph is mechanism velocity, second is mechanism motion, and third is dynamic resistance. Bottom is coil current.

of the breaker chamber during movement of the contacts.

On the other hand, closing of the breaker contacts will result in a mechanical impact, which is inevitably followed by some bouncing periods. Recording of this phenomenon may provide additional information on the state of the contact system and the contact springs, especially if it is taken into account that DRM will provide insights into resistance changes on a milliohm level.

Further simplification of this measurement procedure would lead to the recording of the DRM curve during the open-close or closeopen operations of the HVCB. That way, all the necessary information could be recorded with only one measurement.

SUMMARY

When the circuit breaker is out of service, it generates a financial loss for the utilities. To ensure reliable operation, it is necessary to perform offline tests occasionally. During regular maintenance procedures, all other means must be exhausted before disassembling the interrupting chamber. This implies conducting a series of tests and measurements and using the results for diagnostic purposes. (See photo of High-Voltage Circuit Breaker Testing.)

Tests and measurements should be conducted in the shortest time possible, and the results should be easily comparable with the results obtained in the past. Therefore, it is necessary to find ways to extend the useful data set for the offline testing procedures.

Applying the voltage across the CB coil will trigger a CB operation and cause the contacts to move. Movement of the contacts inside of the chamber leads to changes in the total resistance measured from the breaker terminals. This is the only parameter that can provide insight into the state of contacts on a fully assembled CB. The only way to detect such low changes is to apply a high current through the DRM. The DRM test may be carried out during CB opening and closing operations.

For the CB’s closing operation, the DRM procedure must be slightly modified to protect the power source used and achieve similar test conditions for different testing intervals. This approach will meet the basic test requirement of having comparable results.

Separation and closing of the CB contacts are different physical processes (closing of the contacts is always followed by several bouncing periods), so all these characteristics should be taken into account during diagnostic processes.

Most of the utilities have adapted DRM during opening of the CB as a standard testing procedure during maintenance operations.

High-Voltage Circuit Breaker Testing

I DUSTRY TOPICS

Appropriate cables and test equipment are necessary to perform the test.

The DRM test can also be performed during the closing operation of the HVCB. This test approach does not require any additional connection to the CB terminals. The only modification is adding a connection to the closing coil control.

The time needed to perform the test does not greatly affect the total out-of-service time; the useful data set is extended, and this can lead to better diiagnostics.

Adnan Secic is an R&D Engineer at DV Power, Sweden. As a project leader, he is responsible for development of the Circuit Breaker Analyzer and Timer (CAT) device series. In 2014, Adnan received is M. Sc. degree in EEA (Electronics, Electrical Engineering and Automation).

Radenko Ostojic is a Test at DV Power, Sweden, working on the improvement of CB testing equipment and development of new methods for CB testing

Stockyards Station Shindig

OMNI FORT WORTH HOTEL

MARCH 14-18, 2016

www.powertest.org

888.300.NETA(6382)

New Product Forum

SO MANY WAYS TO CONNECT

Sunday, March 13, 2016, 5:30 PM-8:30 PM

Join us Sunday evening for traditional Texas hospitality and a blazing good time. Swagger into the Stockyards Station and experience the storied history of Fort Worth, the best in Southwest BBQ, a tall cold one, and a rootin’ tootin’ showdown! $155 per person.

Monday, March 14, 2016, 5:00 PM-6:00 PM

Learn about the latest products, technologies, and innovations by leading manufacturers and suppliers in the industry. Stay until the end for a chance to win an exclusive prize.

Hospitality Suites

Monday, March 14, 2016, 6:00 PM-10:00 PM

Mingle with a host of leaders at Monday night’s Hospitality Suites. Talk with experts, find solutions for your business, and catch up on the latest products and services as each sponsoring company shares its own brand of hospitality.

PowerBash 2016

Tuesday, March 15, 2016, 7:00 PM-10:00 PM

Dinner, drinks, dancing, and an awards presentation that acknowledges the best of the best at PowerTest. Each year, PowerTest attendees vote for their favorite presentations, Hospitality Suites, and Trade Show booths. RSVP when you register for PowerTest to reserve your seat! $25 per person.

Sign up for social networking events when you register for PowerTest: Online at powertest.org/registration or by calling the NETA office: 888.300.6382

Accompanied by a spouse or guest? Include them in the fun by adding a Spouse/Guest Pass or Social Pass to your conference registration.

SPOUSE/GUEST PASS Stocked with refreshments, information on local restaurants, shops, tours, and attractions, the Gathering Lounge allows allows guest to connect and enjoy Fort Worth together or on their own. The pass also includes access to the Hospitality Suites, the Trade Show, and PowerBash. $75 per person.

SOCIAL PASS Want to keep it simple? Forego the lounge included in the Spouse/Guest Pass and instead add the Social Pass for guests who want to attend Monday evening’s Hospitality Suites, Tuesday’s Trade Show, and PowerBash. $50 per person.

T O P 1 0 C AREER-B U ILDIN G

TO ATTEND POWERTEST 2016

POWERTEST 2016 IS DESIGNED TO MAKE YOU THINK. IN FACT, IT’S WHERE THE ELECTRICAL POWER SYSTEMS INDUSTRY’S LEADERS COME TO THINK TOGETHER. POWERTEST IS A UNIQUE OPPORTUNITY FOR LEARNING, EXPANDING YOUR TECHNICAL EXPERTISE, AND ENERGIZING YOUR FUTURE.

For many people, the annual PowerTest conference is a permanent part of their annual plan for professional development. They are sold on the value of attending and wouldn’t miss it. If that’s you, use the following information to learn what’s new this year and how to get even more out of your PowerTest 2016 experience.

For others, PowerTest is an interesting prospect, but they aren’t sure if it’s the right event for them or if the benefits are worth the investment. Maybe it’s their boss who needs convincing. If that’s you, this article will give you what you need to know to make an informed decision.

People attend conferences for a variety of reasons, but most of them fall into the categories of learning, networking, career development, and socializing. At Power Test 2016, these activities blur into one another, under a unifying theme of improving performance and safety on the job and better serving your customers.

TOP 10 REASONS TO ATTEND POWERTEST 2016:

1. Leadership. The best way to become a leader is to gain exposure to other industry leaders who inspire, motivate, and encourage growth. It is also a place where you can share your own unique knowledge and interests, and exchange ideas with others attending PowerTest 2016.

2. Reenergization. Going to conferences reenergizes you! It rejuvenates your focus and determination. Being around like-minded people is inspirational and refreshing. It’s uniquely satisfying to engage in real-time idea exchange at PowerTest with someone who has the answers you’re looking for… or maybe a fresh way of approaching an old challenge.

3. Ideas and Strategies. There’s no way you’re leaving PowerTest 2016 without at least one great idea to implement when you get back home — and quite likely, that one idea will more than compensate for the cost of attending. At PowerTest 2016, you will learn new techniques and approaches. You will discover what strategies are working for others who are faced with the same challenges you are.

4. Relationships and Networks. Who doesn’t want to expand the number of people they know in their own industry? PowerTest 2016 is where you will reconnect with old friends and make new ones. It’s an annual reunion of people who have made a difference in each other’s lives and careers — including people who are looking for opportunities to help young

professionals just beginning their journey. Whether experienced or new to the field, you’ll benefit from your access to PowerTest speakers.

5. Mentors. PowerTest is where electrical safety professionals go to give back to their industry. At conferences, connection is king — PowerTest 2016 goes to the next level by providing opportunities for meaningful, often life-long, connections.

6. The Two R’s: Rest and Reflect. We’re not talking about sleep. We’re talking about the opportunity to interrupt the daily grind, change surroundings, and reflect on what you do and where you need to improve. PowerTest 2016 gets you out of the routine and into an inspiring and energizing industry-wide event. You get to immerse yourself — undisturbed — in an atmosphere of people who have the same background and interests as you do. These are your people, and that helps you relax and enjoy everything the conference has to offer you.

7. Education. Learning improves your productivity, and most importantly, your safety prowess which transcends into the safety of those working around you. Not only will you learn the latest industry trends, processes, and technologies, but PowerTest 2016 helps identify areas where your own body of knowledge needs strengthening. It’s the place to get your questions answered. And because PowerTest 2016 offers five days of education opportunities, you can be thoughtful and choosy about the sessions you

attend. PowerTest 2016’s active, participant-driven events support the kind of collaborative learning that drives real results back home.

8. Technology. PowerTest 2016’s Trade Show is the most economical way to view all our industry’s latest technological advancements under one roof. Problem solve with technology experts who are eager to help, grab a delicious lunch included with admission, and stay for the valuable prize drawings after the show! This year’s extended show hours will give attendees and exhibitors the extra time that has been in demand in years past.

wn-Time. This is your ut and talk to people just

9. Technical Do chance to get o like you during the informal events that will take place each day. Breakfasts, lunches, and the many other sponsored social events make it easy to find and talk to like-minded people who might also enjoy discussing the virtues of the square root of three, turboencabulators, what the heck those timecurrent curves for molded-case circuit breakers are good for, and the latest version of 70E and its practical applications, and a host of other crazy, and not so crazy, electrical things. Consider the PowerTest 2016 conference sessions as your jumping-off point for new and interesting conversations.

WHY?

10. Fill in the blank: lkh

:____________.

O

n l y you k now w h at goes here. What do you want to gain from PowerTest 2016? With so much to choose from, you can shape your experience any way you want. PowerTest 2016 gives you the variables, but your formula for success will be designed and executed by you. And remember the adage: “You get out what you put in.” So put in some time at PowerTest 2016 and fill in your blanks.

WHY POWERTEST 2016? ATTENDEES WEIGH

IN

• MEET FACE-TO-FACE WITH PEERS

• GATHER INFORMATION ABOUT PRODUCTS, TECHNIQUES, TRENDS

• ADVANCE YOUR CAREER AND REPUTATION — SEE AND BE SEEN

• GET THE LATEST NEWS, FIND OUT WHAT’S HOT AND WHAT’S NOT

• LEARN TECHNIQUES AND PRACTICES TO APPLY BACK HOME

• SOCIALIZE WITH OTHER MEMBERS OF YOUR PROFESSION

• FIND OUT ABOUT NEW PRODUCTS, KICK THE TIRES, HEAR FROM VENDORS

• SEE DEMOS, COMPARE PRODUCTS

Hopefully this list has helped to illustrate the many reasons why attendees and those who support their attendance should make the choice to invest in PowerTest 2016. The knowledge, experiences, and solutions provided are truly priceless.

Think beyond what the PowerTest 2016 conference can do for you — think about what’s in it for your customers when you return energized, educated, and updated with the latest information you need to make the coming year your most successful year yet.

• EXPOSE YOUR MIND TO NEW IDEAS FROM THE FIELD

• ADD PEOPLE TO YOUR PERSONAL AND PROBLEM-SOLVING NETWORKS

• REPRESENT YOUR COMPANY AS A LEADER

• RENEW ACQUAINTANCES WITH OLD FRIENDS, MAKE NEW ONES

• FORM OPINIONS, MAKE THE EDUCATION YOUR OWN

• FIND SOLUTIONS TO PROBLEMS

• SET BENCHMARKS AND COMPARE YOUR COMPANY TO OTHERS

• AVOID REGRETTING THAT YOU MISSED OUT ON SOMETHING IMPORTANT

• EXPLORE THE WONDERS OF FORTH WORTH

• HAVE FUN!

www.powertest.org

Keynote

Technical

Panels:

SPOTLIGHT JOIN THE

WITH CORPORATE ALLIANCE PARTNERS

EACH YEAR, POWERTEST PROVIDES AN EXCELLENT FORUM FOR PARTICIPATING NETA CORPORATE ALLIANCE PROGRAM PARTNERS TO SHARE PRODUCT INFORMATION AND TECHNOLOGICAL ADVANCES WITH NETA ACCREDITED COMPANY MEMBERS, INDIVIDUAL ALLIANCE PARTNERS, AND CONFERENCE ATTENDEES AT THE POWERTEST TRADE SHOW SPOTLIGHT STAGE.

During each 15-minute presentation, trade show attendees stop to listen in and learn about technological advancements. It’s a great chance to interact with NETA Corporate Alliance Partners and learn more about technology that offers new, innovative solutions to real-world challenges. This year’s topics include: How Important is Electrical Equipment Maintenance, Test Equipment Acquisition Methods Including a Financial Perspective, and A Guided Workflow Approach to Transformer Diagnostic Testing (see complete schedule at right).

The NETA Corporate Alliance Partnership Program is a network for exchanging information across representative segments from all facets of the electrical power industry, sharing new ideas,

research, and strategies to improve quality, safety, and reliability.

NETA periodically identifies companies that support the work of NETA Accredited Companies and invites these companies to join the NETA Corporate Alliance Program. Companies invited to join the Alliance Program have demonstrated their commitment to research and development, advancing technology, improving services, or education and regularly share their findings and knowledge across the industry.

888.300.NETA(6382)

SPOTLIGHT STAGE PRESENTATIONS

SCHEDULE

Spotlight Stage Presentations

Tuesday, March 15, 2016

During the PowerTest 2016 Trade Show in the exhibit hall. Join NETA’s Corporate Alliance Partners as they share in sights and best practices on the Spotlight Stage at PowerTest 2016. Door prize drawing for Spotlight Stage attendance. Drawing at 5:45 PM.

JOIN AND SAVE AT ALLIANCE PARTNERSHIP PROGRAM

POWERTEST 2016

Gold and Standard Alliance Partnership levels have been combined to simplify participation in the program. Alliance Partners benefit from the opportunity to participate in the NETA community, attend Alliance events, network with peers, and access exclusive discounts on NETA events, publications, and continuing education courses.

Alliance Partnership Program benefits include:

• Discount off PowerTest 2016 registration

• 50% discount on one ANSI/NETA Standard

• Invitation to NETA Member and Alliance Partner Meeting

• Invitation to NETA Member and Alliance Partner Luncheon

• 20% off additional NETA publication purchases

• 20% off NETA Online Training and SPTS Courses

• NETA World Journal — annual subscription (online, in print, or both)

• Opportunity to place press releases on the netaworld.org website... and more!

The NETA Alliance Partnership Program is designed for individuals working in or connected to the electrical power systems industry. Seasoned participants in the Alliance Program find that the numerous discounts, opportunities to announce their projects and innovations to the electrical community, and the ability to network with peers and stay informed offers a value far greater than the cost of enrollment.

The NETA Alliance Partnership Program continues to grow with added benefits. The program offers significant savings for people who want to attend PowerTest and take advantage of other program benefits as well.

NETA’s Alliance Committee is working to create even more opportunities for Alliance Partners to gain access to additional technical discussions and information throughout the year. Examples of these efforts include the NETA Member and Alliance Meeting held the Sunday before PowerTest as well as the Member and Alliance Luncheon on Monday at PowerTest.

DOBLE ENGINEERING SEMINAR

BACK BY POPULAR DEMAND, DOBLE ENGINEERING WILL BUILD ON ITS DEBUT DOBLE LABORATORY SEMINAR FROM LAST YEAR WITH A SPECIAL WORKSHOP ON MARCH 18, 2016, WHICH IS DAY FIVE OF POWERTEST 2016. DESIGNED FOR ENGINEERS, CHEMISTS, AND OTHERS RESPONSIBLE FOR REVIEWING DATA TO INTERPRET LABORATORY RESULTS, THIS SEMINAR WILL BE OF PARTICULAR INTEREST TO THOSE WORKING TO DETECT AND IDENTIFY PROBLEMS WITH ELECTRIC APPARATUS.

NETA and Doble have a long history of working together, with many NETA Accredited Companies using Doble equipment and services on a daily basis. Doble has a reputation as an industry leader and contributes regularly to NETA World Journal and through annual presentations at PowerTest. NETA and Doble continue to build on this strong foundation with this one-day learning laboratory, following the regularly scheduled PowerTest events taking place earlier in the week.

Like last year, the seminar will be interactive, combining theoretical background with practical experience and hands-on examples, including case studies illustrating common problems found in the field.

Participants will:

• Learn about the quality of oils on the market today

• Discover how knowing about the aging characteristics of insulating materials can help extend the life of assets

• Learn how to take oil samples, avoiding common pitfalls and saving time and money by sampling only once

• Diagnose apparatus problems with dissolved gas-in-oil analysis

• Find out how to assess the condition of the paper insulation

• Detect the presence of incipient-fault conditions and categorize them

• Establish the correct method of analyzing the moisture-in-oil results

• Study the significance of dissolved and particulate metals and other particle contamination found in electrical apparatus

• Understand how to determine the condition of electrical apparatus using laboratory tests

Presentations include:

• DGA and Interpretation of Dissolved Gases in Oil

• Explosive Gases in Oil and Personnel Safety

• Water, Solubility, Relative Saturation, and Importance in Insulation Systems

• Determination of Solid Insulation Life through DP and Furans

• Dissolved and Particulate Metals in Oil

• Oil Quality Tests, Meeting Specification and In-Service Requirements, What the Results Mean

• Condition Assessment of Load Tap Changers and Oil Circuit Breakers Using Laboratory Oil Tests

• Sampling of Dielectric Liquids and Its Impact on Test Results

LEARN WHAT YOUR OIL RESULTS REALLY MEAN.

DOBLE LABORATORY DIAGNOSTICS SEMINAR AT POWERTEST 2016 | March 18, 2016

Join us for a one day laboratory seminar on Friday, March 18 th at PowerTest 2016. Doble’s laboratory experts will present an interactive session that combines theoretical background with practical experience and hands-on examples. We will share case studies illustrating common problems found in the field.

PARTICIPANTS WILL

• Learn how to take oil samples, avoid common pitfalls and save time and money by sampling only once

• Diagnose apparatus problems with dissolved gas-in-oil analysis

• Find out how to assess the condition of paper insulation

• Detect the presence of incipient-fault conditions and categorize them

• Establish the correct method of analyzing moisture-in-oil results

• Study the significance of dissolved and particulate metals and other particle contamination found in electrical apparatus

• Understand how to determine the condition of electric apparatus using laboratory tests

So you thought school was out?

Training updated for lastest safety standards

ANSI/NETA STANDARDS UPDATE

ANSI/NETA ECS-2015 NEW AMERICAN NATIONAL STANDARD

The ANSI/NETA ECS Standard for Electrical Commissioning of Electrical Power Equipment and Systems, 2015 edition, was approved as an American National Standard on December 3, 2014. This new standard is available for purchase in the NETA Bookstore online at netaworld.org.

The ANSI/NETA ECS describes the systematic process of documenting and placing into service newly installed or retrofitted electrical power equipment and systems. This document shall be used in conjunction with the most recent edition of the ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems. The individual electrical components shall be subjected to factory and field tests, as required, to validate the individual components. It is not the intent of these specifications to provide comprehensive details on the commissioning of mechanical

equipment, mechanical instrumentation systems, and related components.

Voltage classes addressed include:

• Low-Voltage Systems (less than 1,000 volts)

• Medium-Voltage Systems (greater than 1,000 volts and less than 100,000 volts)

• High-Voltage and Extra-High Voltage Systems (greater than 100 kV and less than 1,000 kV)

References

ASHRAE, ANSI/NETA ATS, NECA, NFPA 70E, OSHA, GSA Building Commissioning Guide

ANSI/NETA MTS-2015 NEW EDITION

The ANSI/NETA MTS Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, 2015 edition, was approved as an American National Standard on December 3, 2014, and supersedes the ANSI/NETA MTS2011. This new standard is available for purchase in the NETA Bookstore online at netaworld.org.

The ANSI/NETA MTS contains specifications that cover suggested field tests and inspections available to assess the suitability for continued service and reliability of electrical power equipment and systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational and within applicable standards and manufacturers’ tolerances, and that the equipment and systems are suitable for continued service.

Revisions include:

• New numbering system for more accurate referencing

• Protective relays

• Instrument transformers

• Rotating machinery

• New Table 100.11

• Revised Table 100.1

• Updated references to industry standards

• Many more revisions, all marked in the margins for ease of use

STAN DARD FOR CERTIFICATION OF ELECTRICAL TESTING TECHNICIANS

PARTICIPATION

Comments and suggestions on any of the standards are always welcome and should be directed to the NETA office at neta@netaworld.org or 888-300-6382. To learn more about the NETA standards review and revision process, to purchase these standards, or to get involved, please visit www.netaworld.org or call 888-300-6382.

ANSI/NETA ETT-2015 NEW EDITION

The ANSI/NETA ETT Standard for Certification of Electrical Testing Technicians, 2015 edition, was approved as an American National Standard on December 3, 2014, and will supersede the ANSI/NETA ETT2010. This new standard is available for purchase in the NETA Bookstore online at netaworld.org.

The ANSI/NETA ETT establishes minimum requirements for qualifications, certification, training, and experience for the electrical testing technician. It also provides criteria for documenting qualifications for certification and details the minimum qualifications for an independent and impartial certifying body to certify electrical testing technicians.

ANSI/NETA ATS-201X REVISION IN PROCESS

The ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems began the review and revision process in October 2014 at the Standards Review Council meeting. The ballot pool for this document is now closed, but applications are always accepted for future revisions.

The ANSI/NETA ATS covers the suggested field tests and inspections that are available to assess the suitability for initial energization of electrical power equipment and systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturers’ tolerances, and are installed in accordance with design specifications.

ANSI/NETA STANDARDS UPDATES

INSULATED CONDUCTOR COMMITTEE NEWS

BY RALPH PATTERSON, Power Products & Solutions LLC

The working groups, including engineers and scientists, met April 12-15 in Clearwater Beach, Florida, for the Spring 2015 IEEE/ ICC Meeting. This is an ongoing opportunity for NETA to be recognized, offering a field testing perspective to the working groups as they develop documents. The working groups are comprised of cable manufactures, utilities, test equipment manufacturers, and end users.

GROUP NO. GROUP NAMEACTIVITYCHAIRS

F04WPartial Discharge Testing in the Field (P400.3)New drafts of Sections 6 and 7 were presented to the working group. Levine/ Walton

F05WDamped AC Voltage Testing (P400.4)

F06DDC Field Testing of Extruded Cable Systems

F07D Guide on Neutral Corrosion in MV Underground Cables (1617)

F10D Diagnostic Testing for Cable Joints & Terminations

F11D Constant Voltage AC Field Testing of Cable Systems

DISCUSSION

Final review by the working group was completed, and document will be sent out for balloting. Gulski/ Patterson

Discussion by interested parties to determine if work should proceed to initiate a PAR and activate the group. Larzelere/ Vacant

Draft title, scope, and objectives for a new guide on shield/neutral corrosion in jacketed and unjacketed cables.

Buchholz/ Vacant

Presentations on diagnostic testing of cable accessories. Jiang/ Hayden

Presentations on experiences with AC withstand testing of medium voltage, high voltage, and extra-high voltage cable systems. Fenger/ Denmon

The F11 Discussion Group was able to identify parameters, which will allow us to critique our presentations and determine what methodology will be best suited for field application.

The Insulated Conductors Committee (ICC) is a professional organization within the Power Engineering Society (PES) of the Institute of Electrical and Electronics Engineers (IEEE).

The 2015 Spring Meeting was a great success. We are looking forward to the next meeting this fall in Tucson, Arizona.

Ralph Patterson is President of Power Products and Solutions located in Charlotte, North Carolina. His professional background includes working as a design engineer of transformers and as a specifying engineer of insulated conductors. He has more than 25 years in power engineering, particularly in insulation diagnosis and evaluation of electrical distribution equipment. He serves on the NETA Standards Review Council, is the NETA liaison for the IEEE Insulated Conductor Committees working groups, and received NETA’s 2001 Outstanding Achievement Award

Table 1: Spring 2015 Breakout Working Groups/Discussion Groups Meetings

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IEEE/PES TRANSFORMERS COMMITTEE MEETING Spring 2015

The Spring 2015 IEEE C57 Transformers Committee met in San Antonio, Texas, on April 12-16, 2015. An impressive 63 working groups and 11 subcommittees met during the five-day session. The following working groups’ standards may be of interest or may affect NETA members:

C57.12.10 Standard for Transformers – 230kV and Below, 833/958 through 8333/10417 kVA, Single Phase, and 750/862 through 60000/80000/100000 kVA, Three-Phase without Load Tap Changing; and 3750/4687 through 60000/80000/100000 kVA with Load Tap Changing – Safety Requirements. Draft 0.1 has been posted in the transformer community website. This replaces C57.12.102010. Three task forces on the Clauses 4, 5, and 6 plus Annex A met via web meeting this summer. A motion passed to remove Annex A from the document in its entirety if all of its content is covered in C57.153. The Clause 6 Task Force will perform this review. Reports should be available at the Fall Meeting.

C57.93 Guide for Installation and Maintenance of Liquid-Immersed Power Transformers. This was the initial meeting to revise the guide. A new draft has been prepared and will be sent out prior to the Fall Meeting. NETA has been involved with this standard for several cycles and will be an active contributor to the revision process.

C57.637 Guide for the Reclamation of Mineral Insulating Oil and Criteria for its Use. The working group did not meet during the Spring Meeting because the resolutions of the last ballot had not been completed. Now, balloting on this document was successful, and it has been sent to Revcon for final IEEE approval. There are proposals to eliminate all the tables in this document and have them included in C57.106.

C57.104 Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers. The working group heard two task force reports.

1. A presentation on “IEEE Data Protocol Update” by Don Platts.

2. A presentation on “Diagnostic Methods (Transformer Fault Severity)” by Jim Durkarm and Fredi Jacob.

The working group will hear a presentation on “Diagnostic Methods (Duval Pentagon)” by Claud Beauchemin at the Fall 2015 Meeting.

SPECIFICATIONS AND STANDARDS ACTIVITY

C57.106 Guide for Acceptance and Maintenance of Insulating Mineral Oil in Electrical Equipment. The working group just had its last ballot resolution meeting on August 20, 2015. Since the Spring Meeting, the group has had six, two-hour sessions to resolve the 135 comments. The document was resubmitted for another vote on Monday, August 25, 2015, and received an 89% approval. The re-ballot closes on September 22. As previously reported, this standard and C57.637 have had all references to oil circuit breakers removed.

Alan D. Peterson received his formal education in electrical engineering at Northeastern University, Boston. In addition, he completed advanced studies at the Massachusetts Institute of Technology, Cambridge. He was employed by Brockton Edison Company (now Eastern Edison), Brockton, Massachusetts, through Northeastern's Cooperative Program in the meter, line, and engineering departments. He was inducted into the US Army and served his term of service as an instructor at the US Army Ordinance Guided Missile School at Redstone Arsenal, Alabama. In 1963, Mr. Peterson founded Peterson Electric Company, an electrical construction firm in Huntsville, Alabama. He holds Journeyman and Master Electrician certificates from several states. In 1976, he founded Utility Service Corporation in Huntsville. Utility Service Corporation is an independent testing, engineering, and maintenance organization for electrical power systems and equipment. He served on the national Board of Directors of AIECA (now IEC) and held the offices of National Vice President and National Treasurer. He has served on the National Affairs Subcommittee of the Chamber of Commerce. Peterson has served on several committees of NETA and has held the offices of President and first and second Vice President. He is presently Technical Committee Chair, a member of the Board of Directors, and a member of the Standards Review Council. He is a member of American National Standards Institute (ANSI) Board of Standards Review (BSR). This 13-member board is charged with the approval of all American National Standards. Prior to his appointment to the BSR, he served on ANSI’s Electrical and Electronic Standards Board. Mr. Peterson has been a member of several ANSI Accredited Standards Committees, specifically ANSI/IEEE C-37, ANSI/IEEE C-57 and ANSI/ IEEE C-62.

Power System Acceptance Testing

Commissioning and Start-up

Maintenance

Life-Cycle Extension

Troubleshoot and Repair

Training and Engineering Services

Planning and Operations Support

Project Management

2200 West Valley Hwy North, Suite 100 | Auburn, WA 98001 |

Sigma Six Solutions, Inc.

ANSWERS

1. a. OA ONAN (self-cooled)

ANSWERS

b. FA ONAF (forced-air/air-cooled) — two stages of cooling would be ONAN/ONAF/ONAF.

c. FOA ODAF or OFAF (forced-air/air-cooled) — these transformers have no self-cooled rating and must run their pumps.

d. OA/FOA ONAN/ODAF (self-cooled, with one stage of directed-oil pumping, with fans).

the workers installing the nitrogen bottles were using their feet to push the bottle into its cabinet. The bottle would hit the back of the tank, causing a false trip.

2. a. Buchholz relays are used with conservator tank transformers and detect internal faults by responding to combustible gas generation directly or by abnormal oil flows created by rapid gas generation.

3. a. Sudden pressure relays won’t operate on a gradual increase in main tank pressure; instead, they will operate on a rapid increase in pressure. This is often due to arcing under the oil, but sometimes can be caused by other events. For example, a utility once experienced false tripping on one of its transformers with a sudden pressure relay. They found that

4. a. Only a fiber optic cable can be used to directly measure the hottest-spot temperature. The hot-spot temperature is (theoretically) two-thirds up and one-third into the highvoltage winding. Any metallic object or sensor would cause a short circuit between windings or turns. Don’t expect to see many fiber optic hot-spot temperature detectors in the field. Most will be the type where oil in a separate well is heated by an auxiliary CT and heating element. This is calibrated to approximate the hot-spot temperature.

5. a and c. Hydrogen is so small that some types of hydrogen detection systems use a membrane that only allows it to pass through, while excluding other gases. Hydrogen is always present when combustible gases are created, so it is a reliable method of combustible gas detection.

NFPA Disclaimer: Although Jim White is a member of the NFPA Technical Committee for both NFPA 70E “Standard for Electrical Safety in the Workplace” and NFPA 70B “Recommended Practice for Electrical Equipment Maintenance,” the views and opinions expressed in this message are purely the author’s and shall not be considered an official position of the NFPA or any of its technical committees and shall not be considered to be, nor be relied upon as, a formal interpretation or promotion of the NFPA. Readers are encouraged to refer to the entire text of all referenced documents.

NETA ACCREDITED COMPANIES Setting the

A&F Electrical Testing, Inc.

80 Lake Ave. South, Ste. 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720

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Kevin Chilton

A&F Electrical Testing, Inc.

80 Broad St. 5th Floor

New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 afelectricaltesting@afelectricaltesting.com www.afelectricaltesting.com

Florence Chilton

ABM Electrical Power Solutions

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Doug Bukowski

ABM Electrical Power Solutions

9800 E. Geddes Avenue, Unit A-150 Englewood, CO 80112 (303) 524-6560 Fax: (303) 524-6581

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Brian Smith

ABM Electrical Power Solutions

2142 Rheem Drive Pleasanton, CA 94588 (408) 466-6920

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John Marvulli

ABM Electrical Power Solutions

3940 Ruffin Rd., Ste. C San Diego, CA 92123 (858) 754-7963

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Ben Thomas

ABM Electrical Power Solutions

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Jason Black

ABM Electrical Power Solutions

814 Greenbrier Circle, Ste. E Chesapeake, VA 23320 (757) 548-5690 Fax: (757) 548-5417

www.ABM.com

Mark Anthony Gaughan, III

ABM Electrical Power Solutions

3700 Commerce Dr. #901-903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900

www.ABM.com

Bill Hartman

ABM Electrical Power Solutions 5809 Departure Dr., Ste. 104 Raleigh, NC 27616 (919) 877-1008 Fax: (919) 501-7492

www.ABM.com

Rob Parton

ABM Electrical Power Solutions

317 Commerce Park Dr. Cranberry Township, PA 16066-6427 (724) 772-4638 Fax: (724) 772-6003 william.mckenzie@abm.com www.ABM.com

William (Pete) McKenzie

ABM Electrical Power Solutions 4390 Parliament Place, Ste. S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 www.ABM.com

Frank Ceci

ABM Electrical Power Solutions

3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 ernest.goins@abm.com www.ABM.com

Ernest Goins

ABM Electrical Power Solutions

720 S. Rochester Ave., Suite A Ontario, CA 91761 (800) 597-1225 Fax: (909) 937-6798 www.ABM.com

Mike Bivens

Absolute Testing Services 6829 Guhn Rd. Houston, TX 77040 (832) 467-4446 Fax: (713) 849-3885 rgamble@absolutetesting.com www.texasats.com

Richard Gamble

Accessible Consulting Engineers, Inc. 1269 Pomona Rd., Ste. 111 Corona, CA 92882 (951) 808-1040 info@acetesting.com www.acetesting.com

Iraj Nasrolahi

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 pmaccarthy@advtest.com www.advtest.com

Pat MacCarthy

American Electrical Testing Co., Inc.

480 Neponset St., Building 6 Canton, MA 02021-1970 (781) 821-0121 Fax: (781) 821-0771 sblizard@aetco.us www.99aetco.com

Scott A. Blizard

American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 jpoulin@aetco.us www.99aetco.com

Gerald Poulin

American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 mschacker@aetco.us www.99aetco.com

Michael Schacker

American Electrical Testing Co., Inc. 50 Intervale Rd., Ste. 1 Boonton, NJ 07005 (973) 316-1180 Fax: (781) 316-1181 jsomol@aetco.us www.99aetco.com

Jeff Somol

American Electrical Testing Co., Inc. 4032 Park 65 Dr. Indianapolis, IN 46254 (317) 487-2111 Fax: (781) 821-0771 scanale@aetco.us www.99aetco.com

Stephen Canale

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Ste. 200 Allentown, PA 18104 (215) 219-6800 jmunley@aetco.us www.99aetco.com

Jonathan Munley

American Electrical Testing Co., Inc. 12566 W. Indianola Ave. Avondale, AZ 85392 (480) 383-9242 dmadaglia@aetco.us www.99aetco.com

Donald Madaglia

AMP Quality Energy Services, LLC 4220 West Schrimsher SW Site W1 P.O. Box 526, Huntsville, AL 35804 (256) 513-8255

Brian Rodgers

Apparatus Testing and Engineering 11300 Sanders Dr., Ste. 29 Rancho Cordova, CA 95742 (916) 853-6280 Fax: (916) 853-6258 info@apparatustesting.com www.apparatustesting.com

Harold (Jerry) Carr

Apparatus Testing and Engineering

7083 Commerce Circle, Ste. H Pleasanton, CA 94588 (925) 454-1363 Fax: (925) 454-1499 info@apparatustesting.com www.apparatustesting.com

Harold (Jerry) Carr

Applied Engineering Concepts 1105 N. Allen Ave. Pasadena, CA 91104 (626) 398-3052 Fax: (626) 398-3053 michel.c@aec-us.com www.aec-us.com

Michel Castonguay

BEC Testing 50 Gazza Blvd. Farmingdale, NY 11735 (516) 531-9136 Fax: (631) 249-6115 wfernandez@banaelectric.com www.bectesting.com

William Fernandez

Burlington Electrical Testing Co., Inc.

300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 (221) Fax: (215) 826-0964 waltc@betest.com www.betest.com

Walter P. Cleary

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 cetesting@aol.com

Mark Chapman

CE Power Solutions, LLC 4040 Rev Dr. Cincinnati, OH 45232 (513) 563-6150 Fax: (513) 563-6120 info@cepowersol.net www.cepower.net

Rhonda Harris

CE Power Solutions of Minnesota, LLC 7674 Washington Ave. South Eden Prairie, MN 55344 (877) 968-0281 Fax: (952) 400-8772 jason.thompson@cepower.net www.cepower-mn.net

Jason Thompson

Control Power Concepts

353 Pilot Rd; Ste. B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 www.controlpowerconcepts.com

John Travis

Dude Electrical Testing LLC

145 Tower Dr., Unit# 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386

scott.dude@dudetesting.com www.dudetesting.com

Scott Dude

DYMAX Service, LLC

46918 Liberty Dr. Wixom, MI 48393 (248) 313-6868 Fax: (248) 313-6869 www.dymaxservice.com

Bruce Robinson

DYMAX Service, LLC

4213 Kropf Ave. Canton, OH 44706 (330) 484-6801 Fax: (740) 333-1271 www.dymaxservice.com

Chuck Baker

Eastern High Voltage

11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 joewilson@easternhighvoltage.com www.easternhighvoltage.com

Joseph Wilson

ELECT, P.C.

7400-G Siemens Rd., P.O. Box 2080 Wendell, NC 27591 (919) 365-9775 Fax: (919) 365-9789 btyndall@elect-pc.com www.elect-pc.com

Barry W. Tyndall

Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043 (314) 890-9999 Fax: (314) 890-9998 www.epsii.com

Electric Power Systems, Inc. 557 E. Juanita Ave., #4 Mesa, AZ 85204 (480) 633-1490 Fax: (480) 633-7092 www.epsii.com

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: 407-578-6408 www.epsii.com

Electric Power Systems, Inc.

7000 E. 47th Avenue Drive, Suite 100 Denver, CO 80216 (720) 857-7273 Fax: 303-928-8020 www.epsii.com

Electric Power Systems, Inc. 23823 Andrew Rd. Plainfield, IL 60585 (815) 577-9515 Fax: (815) 577-9516 www.epsii.com

NETA ACCREDITED COMPANIES

Electric Power Systems, Inc. 2601 Center Rd., # 101 Hinckley, OH 44233 (330) 460-3706 Fax: (330) 460-3708 www.epsii.com

Electric Power Systems, Inc.

56 Bibber Pkwy #1 Brunswick, ME 04011 (207) 837-6527 www.epsii.com

Electric Power Systems, Inc. 4100 Greenbriar Dr., Ste. 160 Stafford, TX 77477 (713) 644-5400 www.epsii.com

Electric Power Systems, Inc. 11861 Longsdorf St. Riverview, MI 48193 (734) 282-3311 www.epsii.com

Electric Power Systems, Inc. 827 Union St., Salem, VA 24153 (540) 375-0084 Fax: (540) 375-0094 www.epsii.com

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 Fax: 603-657-7370 www.epsii.com

Electric Power Systems, Inc.

146 Space Park Dr. Nashville, TN 37211 (615) 834-0999 Fax: (615) 834-0129 www.epsii.com

Electric Power Systems, Inc. 8515 Cella Alameda NE, Ste. A Albuquerque, NM 87113 (505) 792-7761 www.epsii.com

Electric Power Systems, Inc. 7140 Dean Martin Drive, Suite 900 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electric Power Systems, Inc.

319 US Hwy. 70 E, Unit E Garner, NC 27529 (919) 322-2670 www.epsii.com

Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

NETA ACCREDITED COMPANIES

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com

Electric Power Systems, Inc. 2495 Boulevard of the Generals Norristown, PA 19403 (610) 630-0286 www.epsii.com

Electric Power Systems, Inc. 1129 East Hwy. 30 Gonzalez, LA 70817 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste. G San Diego, CA 92126 (858) 566-6317 www.epsii.com

Electrical & Electronic Controls 6149 Hunter Rd. Ooltewah, TN 37363 (423) 344-7666 (23) Fax: (423) 344-4494 eecontrols@comcast.net

Michael Hughes

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown, WI 53022 (262) 255-5222 Fax: (262) 242-2360 bill@electricalenergyexperts.com www.electricalenergyexperts.com

William Styer

Electrical Equipment Upgrading, Inc. 21 Telfair Place, Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 kmiller@eeu-inc.com www.eeu-inc.com

Kevin Miller

Electrical Maintenance & Testing Inc. 12342 Hancock St., Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 info@emtesting.com www.emtesting.com

Brian K. Borst

Electrical Reliability Services 1057 Doniphan Park Circle, Ste. A El Paso, TX 79922 (915) 587-9440 Fax: (915) 587-9010 www.electricalreliability.com

Electrical Reliability Services 1775 W. University Dr., Ste. 128 Tempe, AZ 85281 (480) 966-4568 Fax: (480) 966-4569 www.electricalreliability.com

Electrical Reliability Services 1426 Sens Rd. Ste. 5 Houston, TX 77571 (281) 241-2800 Fax: (281) 241-2801 www.electricalreliability.com

Electrical Reliability Services 4099 SE International Way, Ste. 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

Electrical Reliability Services 5909 Sea Lion Place, Ste. C Carlsbad, CA 92010 (858) 695-9551 www.electricalreliability.com

Electrical Reliability Services 8500 Washington Pl. NE, Ste. A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com

Electrical Reliability Services 1380 Greg Street, Ste. 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com

Electrical Reliability Services 2275 Northwest Pkwy SE, Ste. 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501 www.electricalreliability.com

Electrical Reliability Services 7100 Broadway, Ste. 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

Electrical Reliability Services 348 N.W. Capital Dr. Lee's Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 www.electricalreliability.com

Electrical Reliability Services 6900 Koll Center Parkway, Ste. 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436 www.electricalreliability.com

Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 www.electricalreliability.com

Electrical Reliability Services

3535 Emerson Parkway, Ste. A Gonzales, LA 70737 (225) 755-0530 Fax: (225) 751-5055 www.electricalreliability.com

NETA ACCREDITED COMPANIES Setting the

Electrical Reliability Services

245 Hood Rd. Sulphur, LA 70665 (337) 583-2411 Fax: (337) 583-2410 www.electricalreliability.com

Electrical Reliability Services

11000 Metro Pkwy., Ste. 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772 www.electricalreliability.com

Electrical Reliability Services

2222 West Valley Hwy. N., Ste 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 www.electricalreliability.com

Electrical Reliability Services

3412 South 1400 West, Unit A West Valley City, UT 84119 (801) 975-6461 www.electricalreliability.com

Electrical Reliability Services

6351 Hinson St., Ste. B Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

Electrical Reliability Services

9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 www.electricalreliability.com

Electrical Reliability Services

610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 info@electricalreliability.com www.electricalreliability.com

Electrical Testing, Inc. 2671 Cedartown Hwy. Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 steve@electricaltestinginc.com www.electricaltestinginc.com

Electrical Testing Solutions

2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 tmachado@electricaltestingsolutions.com www.electricaltestingsolutions.com

Tito Machado

Elemco Services, Inc. 228 Merrick Rd. , Lynbrook, NY 11563 (631) 589-6343 Fax: (631) 589-6670 courtney@elemco.com www.elemco.com

Courtney O'Brien

EnerG Test

204 Gale Lane Bldg. 2 - 2nd Floor

Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 kbleiler@energtest.com www.energtest.com

Katie Bleiler

Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 info@energisinc.com www.energisinc.com

Mick Petzold

EPS Technology 29 N. Plains Hwy., Ste. 12 Wallingford, CT 06492 (203) 679-0145 www.eps-technology.com

Grounded Technologies, Inc. 10505 S. Progress Way, Ste. 105 Parker, CO 80134 P-(303) 781-2560 F- (303) 781-5240 jodymedina@groundedtech.com www.groundedtech.com

Jody Medina

Grubb Engineering, Inc. 3128 Sidney Brooks San Antonio, Tx 78235 (210) 658-7250 Fax: (210) 658-9805 joy@grubbengineering.com www.grubbengineering.com

Robert D. Grubb Jr.

Hampton Tedder Technical Services 4571 State St. Montclair, CA 91763 (909) 628-1256 x214 Fax: (909) 628-6375 matt.tedder@hamptontedder.com www.hamptontedder.com

Matt Tedder

Hampton Tedder Technical Services 4920 Alto Ave. Las Vegas, NV 89115 (702) 452-9200 Fax: (702) 453-5412 www.hamptontedder.com

Roger Cates

Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax: (480) 967-7762 www.hamptontedder.com

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 Fax: (410) 679-0800 testing@harfordtesting.com www.harfordtesting.com

Vincent Biondino

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 hinrg@comcast.net www.highenergyelectric.com

Charles Blanchard

High Voltage Maintenance Corp. 24 Walpole Park South Dr. Walpole, MA 02081 (508) 668-9205 www.hvmcorp.com

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, Il 60007 (847) 640-0005 www.hvmcorp.com

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com

High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

High Voltage Maintenance Corp. 8320 Brookville Rd. #E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

High Voltage Maintenance Corp. 1250 Broadway, Ste. 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com

High Voltage Maintenance Corp. 9305 Gerwig Ln., Ste. B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

High Voltage Maintenance Corp. 24371 Catherine Industrial Dr, Ste. 207 Novi, MI 48375 (248) 305-5596 Fax: (248) 305-5579 www.hvmcorp.com

High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

High Voltage Service, LLC 4751 Mustang Circle St. Paul, MN 55112 (763) 784-4040 Fax: (763) 784-5397 www.hvserviceinc.com

Mike Mavetz

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 jpertgen@hmt-electric.com www.hmt-electric.com

John Pertgen

Industrial Electric Testing, Inc. 11321 West Distribution Ave. Jacksonville, FL 32256 (904) 260-8378 Fax: (904) 260-0737 gbenzenberg@bellsouth.net www.industrialelectrictesting.com

Gary Benzenberg

Industrial Electric Testing, Inc. 201 NW 1st Ave. Hallandale, FL 33009-4029 (954) 456-7020 www.industrialelectrictesting.com

Industrial Electronics Group 850369 Highway 17 South P.O. Box 1870 Yulee, FL 32041 (904) 225-9529 Fax: (904) 225-0834 butch@industrialgroups.com www.industrialgroups.com

Butch E. Teal

Industrial Tests, Inc. 4021 Alvis Ct., Ste. 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 greg@indtest.com www.industrialtests.com

Greg Poole

Infra-Red Building and Power Service 152 Centre St. Holbrook, MA 02343-1011 (781) 767-0888 Fax: (781) 767-3462 tom.mcdonald@infraredbps.com www.infraredbps.com

Thomas McDonald Sr.

Longo Electrical-Mechanical, Inc. One Harry Shupe Blvd., Box 511 Wharton, NJ 07885 (973) 537-0400 Fax: (937) 537-0404 jmlongo@elongo.com www.elongo.com

Joe Longo

Longo Electrical-Mechanical, Inc. 1625 Pennsylvania Ave. Linden, NJ 07036 (908) 925-2900 Fax: (908) 925-9427 jmlongo@elongo.com www.elongo.com

Joe Longo

Longo Electrical-Mechanical, Inc. 1400 F Adams Rd. Bensalem, PA 19020 (215) 638-1333 Fax: (215) 638-1366 jmlongo@elongo.com www.elongo.com

Joe Longo

M&L Power Systems, Inc.

109 White Oak Ln., Ste. 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 milind@mlpower.com www.mlpower.com

Milind Bagle

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 info@magnaiv.com www.magnaiv.com

Virgina Balitski

Magna IV Engineering 200, 688 Heritage Dr. Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 info.calgary@magnaiv.com

Dave Emerson

Magna IV Engineering 8219D Fraser Ave. Fort McMurray, AB T9H 0A2 Canada (780) 791-3122 Fax: (780) 791-3159 info.fmcmurray@magnaiv.com

Ryan Morgan

Magna IV Engineering 96 Inverness Dr. East, Unit R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 info.denver@magnaiv.com Aric Proskurniak

Magna IV Engineering Avenida del Condor #590 Oficina 601 Huechuraba, Santiago 8580676 Chile +(56) 9-9-517-4642 info.chile@magnaiv.com

Harvey Mendoza

Magna IV Engineering 1040 Winnipeg St. Regina , SK S4R 8P8 Canada (306) 585-2100 Fax: (306) 585-2191 info.regina@magnaiv.com

Andrew Westerman

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020 Scott Nixon

National Field Services 649 Franklin St. Lewisville, TX 75057 (972) 420-0157 www.natlfield.com

Eric Beckman

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 Shashi@N-E-T-Inc.com www.n-e-t-inc.com

Shashikant B. Bagle

North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 ncetest@aol.com www.ncetest.com

Robert Messina

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 ldetterman@northerntesting.com www.northerntesting.com

Lyle Detterman

Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 lorne@orbisengineering.net www.orbisengineering.net

Lorne Gara

Pacific Power Testing, Inc. 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 steve@pacificpowertesting.com www.pacificpowertesting.com

Steve Emmert

NETA ACCREDITED COMPANIES

Pacific Powertech, Inc. #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 jkonkin@pacificpowertech.ca www.pacificpowertech.ca

Josh Konkin

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 rcastro@phasorinc.com

Rafael Castro

Potomac Testing, Inc. 1610 Professional Blvd., Ste. A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 kbassett@potomactesting.com www.potomactesting.com

Ken Bassett

Power & Generation Testing, Inc. 480 Cave Rd. Nashville, TN 37210 (615) 882-9455 Fax: (615) 882-9591 mose@pgti.net www.pgti.net

Mose Ramieh

Power Engineering Services, Inc. 9179 Shadow Creek Lane Converse, TX 78109 (210) 590-4936 Fax: (210) 590-6214 engelke@pe-svcs.com www.pe-svcs.com

Miles R. Engelke

POWER PLUS Engineering, Inc. 46575 Magellan Novi, MI 48377 (248) 344-0200 Fax: (248) 305-9105 smancuso@epowerplus.com www.epowerplus.com

Salvatore Mancuso

Power Products & Solutions, LLC 12465 Grey Commercial Rd. Midland, NC 28107 (704) 573-0420 x12 Fax: (704) 573-3693 ralph.patterson@powerproducts.biz www.powerproducts.biz

Ralph Patterson

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 ralph.patterson@powerproducts.biz www.powerproducts.biz

Raymond Pesaturo

Power Services, LLC 998 Dimco Way, P.O. Box 750066 Centerville, OH 45475 (937) 439-9660 Fax: (937) 439-9611

mkbeucler@aol.com

Mark Beucler

Power Solutions Group, Ltd. 425 W. Kerr Rd. Tipp City, OH 45371 (937) 506-8444 Fax: (937) 506-8434 bwilloughby@powersolutionsgroup.com www.powersolutionsgroup.com

Barry Willoughby

Power Solutions Group, Ltd. 135 Old School House Rd. Piedmont, SC 29673 (864) 845-1084 Fax:: (864) 845-1085 fcrawford@powersolutionsgroup.com www.powersolutionsgroup.com

Anthony Crawford

Power Solutions Group, Ltd. 670 Lakeview Plaza Blvd. Columbus, OH 43085 (614) 310-8018 sspohn@powersolutionsgroup.com www.powersolutionsgroup.com

Stuart Spohn

Power Systems Testing Co. 4688 W. Jennifer Ave., Ste. 108 Fresno, CA 93722 (559) 275-2171 ext 15 Fax: (559) 275-6556 dave@pstcpower.com www.powersystemstesting.com

David Huffman

Power Systems Testing Co. 600 S. Grand Ave., Ste. 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

Power Systems Testing Co. 6736 Preston Ave, Ste. E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

Power Test, Inc. 2200 Highway 49 Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 rich@powertestinc.com www.powertestinc.com

Richard Walker

POWER Testing and Energization, Inc. 14006 NW 3rd Ct., Ste. 101 Vancouver, WA 98685 (360) 597-2800 Fax: (360) 576-7182 chris.zavadlov@powerte.com www.powerte.com

Chris Zavadlov

NETA ACCREDITED COMPANIES

POWER Testing and Energization, Inc.

731 E. Ball Rd., Ste. 100 Anaheim, CA 92805 (714) 507-2702

www.powerte.com

POWER Testing and Energization, Inc.

22035 70th Ave. South Kent, WA 98032 (253) 872-7747

www.powerte.com

Powertech Services, Inc.

4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 kirkd@powertechservices.com www.powertechservices.com

Kirk Dyszlewski

Precision Testing Group

5475 Highway 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

glenn@precisiontestinggroup.com

Glenn Stuckey

Premier Power Maintenance Corporation

6525 Guion Rd. Indianapolis, IN 46268 (317) 879-0660

kevin.templeman@premierpower.us www.premierpowermaintenance.com

Kevin Templeman

Premier Power Maintenance Corporation 2725 Jason Rd. Ashland, KY 41102 (606) 929-5969

jay.milstead@premierpower.us www.premierpowermaintenance.com

Jay Milstead

Premier Power Maintenance Corporation

3066 Finley Island Cir NW Decatur, AL 35601 (256) 355-1444

johnnie.mcclung@premierpower.us www.premierpowermaintenance.com

Johnnie McClung

Premier Power Maintenance Corporation 4301 Iverson Blvd., Ste. H Trinity, AL 35673 (256) 355-3006

kevin.templeman@premierpower.us www.premierpowermaintenance.com

Kevin Templeman

Premier Power Maintenance Corporation

7301 E County Road 142 Blytheville, AR 72315 (870) 762-2100

kevin.templeman@premierpower.us www.premierpowermaintenance.com

Kevin Templeman

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620

brian.ellegiers@premierpower.us www.premierpowermaintenance.com

Brian Ellegiers

Premier Power Maintenance Corporation

4537 S. Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660

kevin.templeman@premierpower.us www.premierpowermaintenance.com

Kevin Templeman

PRIT Service, Inc.

112 Industrial Dr., P.O. Box 606 Minooka, IL 60447 (815) 467-5577 Fax: (815) 467-5883

Rod.Hageman@pritserviceinc.com

www.pritserviceinc.com

Rod Hageman

Reuter & Hanney, Inc.

149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 mikereuter@reuterhanney.com www.reuterhanney.com

Michael Reuter

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: 703-263-1478 www.reuterhanney.com

Reuter & Hanney, Inc.

11620 Crossroads Circle, Suites D-E Middle River, MD 21220 (410) 344-0300 Fax: (410) 335-4389 www.reuterhanney.com

Michael Jester

REV Engineering, LTD 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 rdavidson@reveng.ca www.reveng.ca

Roland Nicholas Davidson, IV

Saber Power Services 9841 Saber Power Lane Rosharon, TX 77583-5188 (713) 222-9102 info@saberpower.com www.saberpower.com

Mark Reid

Scott Testing Inc. 1698 5th St. Ewing, NJ 08638 (609) 882-2400 Fax: (609) 882-5660

rsorbello@scotttesting.com www.scotttesting.com

Russ Sorbello

Sentinel Power Services, Inc. 7517 E. Pine St. Tulsa, OK 74115 (918) 359-0350 gellis@spstulsa.com www.sentinelpowerservices.com

Greg Ellis

Sentinel Power Services, Inc. 1110 West B St., Ste. H Russellville, AR 72801 (918) 359-0350 gellis@spstulsa.com www.sentinelpowerservices.com

Greg Ellis

Shermco Industries 2425 E. Pioneer Dr. Irving, TX 75061 (972) 793-5523 Fax: (972) 793-5542 rwidup@shermco.com www.shermco.com

Ron Widup

Shermco Industries 1705 Hur Industrial Blvd. Cedar Park, TX 78613 (512) 267-4800 Fax: (512) 258-5571 cking@shermco.com www.shermco.com

Chris King

Shermco Industries 33002 FM 2004 Angleton, TX 77515 (979)848-1406 Fax: (979) 848-0012 cking@shermco.com www.shermco.com

Chris King

Shermco Industries 1357 N. 108th E. Ave. Tulsa, OK 74116 (918) 234-2300 jharrison@shermco.com www.shermco.com

Jim Harrison

Shermco Industries 796 11th St. Marion, IA 52302 (319) 377-3377 Fax: (319) 377-3399 jedwards@shermco.com www.shermco.com

Jason Edwards

Shermco Industries 2100 Dixon St., Ste. C Des Moines, IA 50316 (515) 263-8482 jedwards@shermco.com www.shermco.com

Jason Edwards

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 Fax: (614) 836-8557 jharrison@shermco.com www.shermco.com

Jim Harrison

Shermco Industries 998 East Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 Fax: (651) 484-7686 jedwards@shermco.com www.shermco.com

Jason Edwards

Shermco Industries 12000 Network Blvd., Bldg D,, Ste. 410 San Antonio, TX 78249 (512) 267-4800 Fax: (512) 267-4808 cking@shermco.com www.shermco.com

Chris King

Shermco Industries Canada Inc. 1033 Kearns Crescent, Box 995 Regina, SK S4P 3B2 Canada (306) 949-8131 Fax: (306) 522-9181 kheid@magnaelectric.com www.shermco.com

Kerry Heid

Shermco Industries Canada Inc. 851-58th St. East Saskatoon, SK S7K 6X5 Canada (306) 955-8131 Fax: (306) 955-9181 ajaques@magnaelectric.com www.shermco.com

Adam Jaques

Shermco Industries Canada Inc. 3731-98 St. Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 468-9646 cgrant@magnaelectric.com www.shermco.com

Cal Grant

Shermco Industries Canada Inc. 3430 25th St. NE Calgary, AB T1Y 6C1 Canada (403) 769-9300 Fax: (403)769-9369 cgrant@magnaelectric.com www.shermco.com

Cal Grant

Shermco Industries Canada Inc.

1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 cbrandt@magnaelectric.com www.shermco.com

Curtis Brandt

Sigma Six Solutions, Inc.

2200 West Valley Hwy., Ste. 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 jwhite@sigmasix.com www.sigmasix.com

John White

Southern New England Electrical Testing, LLC

3 Buel St., Ste. 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 dave.asplund@sneet.org www.sneet.org

David Asplund, Sr.

Southwest Energy Systems, LLC

2231 East Jones Ave., Ste. A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 bob.sheppard@southwestenergysystems.com www.southwestenergysystems.com

Robert Sheppard

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 robtaurus@tauruspower.com www.tauruspower.com

Rob Bulfinch

Taurus Power & Controls, Inc. 6617 S. 193rd Place, Ste. P104 Kent, WA 98032 (425) 656-4170 Fax: (425) 656-4172 jiml@tauruspower.com www.tauruspower.com

Jim Lightner

3C Electrical Co., Inc.

40 Washington St. Westborough, MA 01581 (508) 881-3911 Fax: (508) 881-4814 jim@three-c.com www.three-c.com

Jim Cialdea

3C Electrical Co., Inc. 72 Sanford Dr. Gorham, ME 04038 (800) 649-6314 Fax: (207) 782-0162 jim@three-c.com www.three-c.com

Jim Cialdea

Tidal Power Services, LLC

4202 Chance Lane Rosharon, TX 77583 (281) 710-9150 Fax: (713) 583-1216

monty.janak@tidalpowerservices.com www.tidalpowerservices.com

Monty C. Janak

Tidal Power Services, LLC

8184 Highway 44, Ste. 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com

Darryn Kimbrough

Tidal Power Services, LLC 1056 Mosswood Dr. Sulphur, LA 70663 (337) 558-5457 Fax: (337) 558-5305 www.tidalpowerservices.com

Steve Drake

Tony Demaria Electric, Inc.

131 West F St. Wilmington, CA 90744 (310) 816-3130 (310) 549-9747 neno@tdeinc.com www.tdeinc.com

Nenad Pasic

Trace Electrical Services & Testing, LLC

293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 jvasta@tracetesting.com www.tracetesting.com

Joseph Vasta

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 GEWalls@UISCorp.com www.uiscorp.com

Gary E. Walls

Utility Service Corporation 4614 Commercial Dr. NW Huntsville, AL 35816-2201 (256) 837-8400 Fax: (256) 837-8403 apeterson@utilserv.com www.utilserv.com

Alan D. Peterson

Western Electrical Services, Inc. 14311 29th St. East Sumner , WA 98390 (253) 891-1995 Fax: (253) 891-1511 dhook@westernelectricalservices.com www.westernelectricalservices.com

Dan Hook

Western Electrical Services, Inc. 3676 W. California Ave., #C, 106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 rcoomes@westernelectricalservices.com www.westernelectricalservices.com

Rob Coomes

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 carcher@westernelectricalservices.com www.westernelectricalservices.com

Craig Archer

Western Electrical Services, Inc. 4510 NE 68th Dr., Ste. 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 Tasciutto@westernelectricalservices.com www.westernelectricalservices.com

Tony Asciutto

This issue’s advertisers are identified

Please thank these advertisers by telling them you saw their advertisement in YOUR magazine –NETA World.

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Don Platts Senior Engineer

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